10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

Or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From                     to                     

Commission File Number 0-7406

PrimeEnergy Corporation

(Exact name of registrant as specified in its charter)

Delaware	84-0637348
(state or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
9821 Katy Freeway, Houston, Texas	77024
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 735-0000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, par value $.10 per share

(Title of Class)

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate whether Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a small reporting company.

Large Accelerated Filer	¨	Accelerated Filer	¨
Non-Accelerated Filer	¨	Smaller Reporting Company	x

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of the voting stock of the Registrant held by non-affiliates, computed by reference to the average bid and asked price of such common equity as of the last business day of the Registrant’s most recently completed second fiscal quarter, was $52,677,788

The number of shares outstanding of each class of the Registrant’s Common Stock as of March 24, 2014 was 2,369,552 shares, Common Stock, $0.10 par value.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s proxy statement to be furnished to stockholders in connection with its Annual Meeting of Stockholders to be held in May 2014, are incorporated by reference in Part III hereof.

TABLE OF CONTENTS

PART I
	Item  1.	Business	3
	Item  1A.	Risk Factors	14
	Item  1B.	Unresolved Staff Comments	20
	Item  2.	Properties	20
	Item  3.	Legal Proceedings	26
PART II
	Item  5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
	Item  6.	Selected Financial Data	28
	Item  7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
	Item  7A.	Quantitative and Qualitative Disclosures About Market Risk	33
	Item  8.	Financial Statements and Supplementary Data	33
	Item  9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	33
	Item  9A.	Controls and Procedures	33
	Item  9B.	Other Information	34
PART III
	Item  10.	Directors, Executive Officers and Corporate Governance	35
	Item  11.	Executive Compensation	35
	Item  12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	35
	Item  13.	Certain Relationships and Related Transactions, and Director Independence	35
	Item  14.	Principal Accountant Fees and Services	35
PART IV
	Item  15.	Exhibits and Financial Statement Schedules	36
SIGNATURES			39
FINANCIAL STATEMENTS:
	Index to Consolidated Financial Statements		F-1

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PrimeEnergy Corporation

FORM 10-K ANNUAL REPORT

For the Fiscal Year Ended

December 31, 2013

PART I

Item 1. BUSINESS.

General

This Report may contain statements relating to the future results of the Company that are considered “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 (the “PSLRA”). In addition, certain statements may be contained in the Company’s future filings with the SEC, in press releases, and in oral and written statements made by or with the approval of the Company that are not statements of historical fact and constitute forward-looking statements within the meaning of the PSLRA. Such forward-looking statements, in addition to historical information, which involve risk and uncertainties, are based on the beliefs, assumptions and expectations of management of the Company. Words such as “expects”, ‘believes”, “should”, “plans”, “anticipates”, “will”, “potential”, “could”, “intend”, “may”, “outlook”, “predict”, “project”, “would”, “estimates”, “assumes”, “likely” and variations of such similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, the possibility of drilling cost overruns and technical difficulties, volatility of oil and gas prices, competition, risks inherent in the Company’s oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, and the Company’s ability to replace and expand oil and gas reserves. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. The forward looking statements are made as of the date of this Report and other than as required by the federal securities laws, the Company assumes no obligation to update the forward-looking statement or to update the reasons why actual results could differ from those projected in the forward-looking statements.

PrimeEnergy Corporation (the “Company”) was organized in March, 1973, under the laws of the State of Delaware.

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana. All of our oil and gas properties and interests are located in the United States. Through our subsidiaries Prime Operating Company, Southwest Oilfield Construction Company, Eastern Oil Well Service Company and EOWS Midland Company, we act as operator and provide well servicing support operations for many of the onshore oil and gas wells in which we have an interest, as well as for third parties. We have owned and operated properties in the Gulf of Mexico through our subsidiary Prime Offshore L.L.C., formerly F-W Oil Exploration L.L.C. We are also active in the acquisition of producing oil and gas properties through joint ventures with industry partners. Our subsidiary, PrimeEnergy Management Corporation (“PEMC”), acts as the managing general partner of eighteen oil and gas limited partnerships (the “Partnerships”), and acts as the managing trustee of two asset and income business trusts (“the Trusts”).

Exploration, Development and Recent Activities

The Company’s activities include development and exploratory drilling. Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential.

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As of December 31, 2013, we had net capitalized costs related to proved oil and gas properties of $195 million. Total expenditures for the acquisition, exploration and development of our properties during 2013 were $26 million of which $8 thousand related to exploration costs expensed during 2013. In addition, during 2013 we spent $8 million to update and increase our field service equipment. Proved reserves as of December 31, 2013, were 30,250 thousand barrels of oil equivalent (“MBoe”) which consisted of 47% proved developed reserves and 53% proved undeveloped reserves.

Significant 2013 Activity

During 2013, we participated in drilling a total of 23 gross (13.60 net) wells, of which all were successful completions. This included 9 development wells in our West Texas drilling program and the drilling of 14 wells in our Mid-Continent region.

In July 2013, we entered into a $10.0 million Loan and Security Agreement that is secured by substantially all of our field service equipment. These proceeds were used to pay down on our revolving credit facility. During 2013, we decreased our outstanding debt under the credit facility by $9.5 million from $122.0 million at December 31, 2012 to $112.5 million as of December 31, 2013. As of December 31, 2013 we have $27.5 million available for future borrowings.

We believe that our diversified portfolio approach to our drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile.

We attempt to assume the position of operator in all acquisitions of producing properties. We will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests and are actively pursuing the acquisition of producing properties. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to increase our net worth and increase our oil and gas reserve base.

We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana, and we own a substantial amount of well servicing equipment. We do not own any refinery or marketing facilities, and do not currently own or lease any bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems. All of our oil and gas properties and interests are located in the United States.

In the past, the supply of gas has exceeded demand on a cyclical basis, and we are subject to a combination of shut-in and/or reduced takes of gas production during summer months. Prolonged shut-ins could result in reduced field operating income from properties in which we act as operator.

Exploration for oil and gas requires substantial expenditures particularly in exploratory drilling in undeveloped areas, or “wildcat drilling.” As is customary in the oil and gas industry, substantially all of our exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business.

Summaries of our oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral and royalty interests are set forth under Item 2., “Properties,” below. Summaries of our oil and gas reserves, future net revenue and present value of future net revenue are also set forth under Item 2., “Properties—Reserves”, below.

Well Operations

Our operations are conducted through our principal offices in Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma City, Oklahoma, and Charleston, West Virginia. We currently operate

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1,609 wells, 350 through the Houston office, 380 through the Midland office, 383 through the Oklahoma City office and 496 through the Charleston, West Virginia office. Substantially all of the wells we operate are wells in which we have an interest.

We operate wells pursuant to operating agreements which govern the relationship between us, as operator, and the other owners of working interests in the properties, including the Partnerships, Trusts and joint venture participants. For each operated well, we receive monthly fees that are competitive in the areas of operations and also are reimbursed for expenses incurred in connection with well operations.

The Partnerships, Trusts and Joint Ventures

Since 1975, PEMC has acted as managing general partner of various partnerships, trusts and joint ventures.

PEMC, as managing general partner of the Partnerships and managing trustee of the Trusts, is responsible for all Partnership and Trust activities, the drilling of development wells and the production and sale of oil and gas from productive wells. PEMC also provides administration, accounting and tax preparation for the Partnerships and Trusts from our offices in Stamford, Connecticut. PEMC is liable for all debts and liabilities of the Partnerships and Trusts, to the extent that the assets of a given limited partnership or trust are not sufficient to satisfy its obligations. We stopped sponsoring partnerships and trusts in 1992. Today there are only 18 partnerships and two trusts remaining. The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now administered by PEMC is approximately 2,076.

Regulation

Regulation of Oil and Natural Gas Exploration and Production:

Exploration and production operations of oil and natural gas are subject to various types of regulations under a wide range of local, state and federal statutes, rules, orders and regulations. These regulations include requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Our offshore operations were conducted on federal leases which are administered by the Bureau of Ocean Energy Management (the “BOEM”) and are required to comply with the regulations and orders promulgated by the BOEM under the Outer Continental Shelf Lands Act (“OCSLA”). These leases required compliance with detailed BOEM, Bureau of Safety and Environmental Enforcement (the “BSEE”), and other government agency regulations and orders that are subject to interpretation and change. The BOEM and BSEE have promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines.

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The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions affecting operations.

Regulation of Transportation and Sale of Natural Gas:

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended (“NGA”), the Natural Gas Policy Act of 1978, as amended (“NGPA”), and regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”) and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended (the “Decontrol Act”). Effective January 1, 1993, the Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas and deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005, as amended (the “2005 Act”), the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established new regulations that are intended to increase natural gas pricing transparency through, among other things, requiring market participants to report their gas sales transactions annually to the FERC, and new regulations that require certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points on their systems. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC’s regulations. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties in an effort to add greater fairness, consistency and transparency to its enforcement program.

Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices we receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.

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The OCSLA, which is administered by the BOEM and the FERC, requires that all pipelines operating on or across the Outer Continental Shelf (“OCS”) provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. On June 18, 2008, the BOEM issued a final rule, effective August 18, 2008, that implements a hotline, alternative dispute resolution procedures, and complaint procedures for resolving claims of having been denied open and nondiscriminatory access to pipelines on the OCS.

In December 2007, the FERC issued rules (Order No. 704) requiring that any market participant that engages in wholesale sales or purchases of natural gas that equal or exceed 2.2 million British thermal units (“MMBtu”) during a calendar year must annually report, starting May 1, 2009, such sales and purchases to the FERC. These rules are intended to increase transparency of the wholesale natural gas markets and assist the FERC in monitoring such markets and in detecting market manipulation.

Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from the effect of such regulation on competitors.

Regulation of Transportation of Oil:

Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service, and that such service not be unduly discriminatory or preferential.

Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 2.65 percent should be the oil pricing index for the five-year period beginning July 1, 2011. The result of indexing is a “ceiling rate” for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost-of-service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of the Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the

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services provided, that were a basis for the rate. There is no such limitation on complaints alleging that the pipeline’s rates or term and conditions of service are unduly discriminatory or preferential.

Another FERC matter that may impact our transportation costs relates to a policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We currently do not transport any of our oil or natural gas liquids on a pipeline structured as a master limited partnership.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe the regulation of oil transportation rates will not affect our operations in any way that is materially different from the effect of such regulation on competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe access to oil pipeline transportation services generally will be available to us to the same extent as to competitors.

Environmental Regulations:

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), the Federal Oil Pollution Act of 1990, as amended (“OPA”), the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), the Safe Drinking Water Act of 1974, as amended (the “Safe Drinking Water Act”), and the Federal Clean Air Act, as amended (the “Clean Air Act”) affect our operations and costs. In particular, exploration, development and production operations, activities in connection with storage and transportation of oil and other hydrocarbons and use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

• impose substantial liabilities for pollution resulting from operations.

Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief. Changes in environmental laws and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the oil and natural gas industry in general. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production

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operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

The transition zone and shallow-water areas of the U.S. Gulf Coast are ecologically sensitive. Environmental issues have led to higher drilling costs and a more difficult and lengthy well permitting process. U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

As with the industry generally, compliance with existing regulations increases the overall cost of business. The areas affected include:

• unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water;

• capital costs to drill exploration and development wells primarily related to the management and disposal of drilling fluids and other oil and natural gas exploration wastes; and

• capital costs to construct, maintain and upgrade equipment and facilities.

Superfund. The CERCLA, also known as the “Superfund” law, and comparable state laws and regulations imposes liability, without regard to fault or the legality of the original conduct, on certain parties with respect to the release of hazardous substances into the environment. These parties include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such parties may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the Environmental Protection Agency (“EPA”), and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substance released into the environment. In the course of ordinary operations, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

We currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under or from the properties currently owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, these properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

• to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators;

• to clean up contaminated property, including contaminated groundwater; or

• to perform remedial operations to prevent future contamination.

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At this time, we do not believe that we are associated with any Superfund site and have not been notified of any claim, liability or damages under CERCLA.

Oil Pollution Act of 1990. The OPA and regulations thereunder impose liability on responsible parties for damages resulting from oil spills into or upon navigable waters, and adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150.0 million depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in the oil and gas industry. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA and believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on our operations.

U.S. Environmental Protection Agency. The U.S. Environmental Protection Agency regulations address the disposal of oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs that follow. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, oil and natural gas wastes are regulated by the Underground Injection Control program under the Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility. We have coverage under the Region VI National Production Discharge Elimination System Permit for discharges associated with exploration and development activities. We take the necessary steps to ensure all offshore discharges associated with a proposed operation, including produced waters, will be conducted in accordance with the permit.

Resource Conservation and Recovery Act. The RCRA is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because the operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

Clean Water Act. The Clean Water Act and resulting regulations imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain

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other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges.

Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Safe Drinking Water Act. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by the permits could subject us to civil and/or criminal enforcement. We believe we are in compliance in all material respects with the requirements of applicable state underground injection control programs and permits.

Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids, usually consisting mostly of water but typically including small amounts of several chemical additives, as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

Greenhouse Gas. Based on findings made by the EPA in December 2009 that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that

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will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources, should such sources exceed threshold emission levels.

While Congress has, from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances for emitting those GHGs.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future federal laws or regulations that impose reporting obligations on us with respect to, or require the elimination of GHG emissions from, our equipment or operations could have an adverse effect on our cost of doing business and could adversely affect demand for the oil and gas we produce.

Marine Protected Areas. Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”) in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

Marine Mammal and Endangered Species. Federal Lease Stipulations include regulations regarding the taking of protected marine species (sea turtles, marine mammals, Gulf sturgeon and other listed marine species). The Bureau of Safety and Environmental Enforcement (“BSEE”) also issue numerous regulations under the nomenclature Notice to Lessees and Operators (“NTL”) that provide formal guidelines on implementation of OCS regulations and standards. We believe we are in compliance in all material respects with the requirements regarding protection of marine species.

Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including OCSLA, the National Environmental Policy Act (“NEPA”), and the Coastal Zone Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires the U.S. Department of Interior (“DOI”) to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the DOI, we must certify that we will conduct our activities in a manner consistent with an applicable program.

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Lead-Based Paints. Various pieces of equipment and structures we own may have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, this would increase the cost of disposal. High lead levels in the paint might also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and BSEE to ensure worker safety during paint removal.

Air Pollution Control. The Clean Air Act and state air pollution laws adopted to fulfill its mandates provide a framework for national, state and local efforts to protect air quality. Operations utilize equipment that emits air pollutants subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Air emissions associated with offshore activities are projected using a matrix and formula supplied by BSEE, which has primacy from the EPA for regulating such emissions.

Naturally Occurring Radioactive Materials. Naturally Occurring Radioactive Materials (“NORM”) are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection, treatment, storage and disposal of NORM waste, management of waste piles, containers and tanks, and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards established by the states, as applicable.

Taxation

Our oil and gas operations are affected by federal income tax laws applicable to the petroleum industry. For U.S income tax reporting purposes, intangible drilling and development costs incurred or borne during the year are permitted to be deducted currently, rather than capitalized. As an independent producer, we are also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced, if such percentage depletion exceeds cost depletion. Generally, this deduction is computed based upon the lesser of 100% of the net income, or 15% of the gross income from a property, without reference to the basis in the property. The amount of the percentage depletion deduction so computed which may be deducted in any given year is limited to 65% of taxable income. Any percentage depletion deduction disallowed due to the 65% of taxable income test may be carried forward indefinitely.

See Notes 1 and 9 to the consolidated financial statements included in this Report for a discussion of accounting for income taxes.

Competition and Markets

The business of acquiring producing properties and non-producing leases suitable for exploration and development is highly competitive. Our competition, in our efforts to acquire both producing and non-producing properties, include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to us. Furthermore, domestic producers of oil and gas must not only compete with each other in marketing their output, but must also compete with producers of imported oil and gas and alternative energy sources such as coal, nuclear power and hydroelectric power. Competition among petroleum companies for favorable oil and gas properties and leases can be expected to increase.

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The availability of a ready market for any oil and gas produced by us at acceptable prices per unit of production will depend upon numerous factors beyond our control, including the extent of domestic production and importation of oil and gas, the proximity of our producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels. There is no assurance that we will be able to market all of the oil or gas produced by us or that favorable prices can be obtained for the oil and gas production.

Major Customers

Listed below are the percent of our total oil and gas sales made to each of our customers whose purchases represented more than 10% of our oil and gas sales in 2013.

Oil Purchasers:
Plains All American Inc.	52	%
Sunoco, Inc.	28	%
Gas Purchasers:
Atlas Pipeline Mid-Continent	40	%
Unimark LLC	13	%

Although there are no long-term purchasing agreements with these purchasers, we believe that they will continue to purchase our oil and gas products and, if not, could be readily replaced by other purchasers.

Employees

At March 1, 2014, we had 238 full-time and 6 part-time employees, 37 of whom were employed at our principal offices in Houston, Texas, at the offices of Prime Operating Company, Eastern Oil Well Service Company, EOWS Midland Company and Prime Offshore L.L.C., 13 employees in Stamford, Connecticut, and 194 employees who were primarily involved in our district operations in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia.

Item 1A. RISK FACTORS.

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Natural gas prices increased from an average price of $2.75 per MMbtu in 2012 to an average price of $3.73 per MMbtu in 2013. Oil prices increased from an average price of $94.05 per barrel in 2012 to an average price of $97.98 per barrel in 2013. Depressed prices in the future would have a negative impact on our future financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

• the level of consumer product demand;

• weather conditions;

• political conditions in natural gas and oil producing regions, including the Middle East;

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• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• the price of foreign imports;

• actions of governmental authorities;

• pipeline capacity constraints;

• inventory storage levels;

• domestic and foreign governmental regulations;

• the price, availability and acceptance of alternative fuels; and

• overall economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

Drilling natural gas and oil wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

• unexpected drilling conditions, pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with governmental requirements; and

• shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

• the results of exploration efforts and the acquisition, review and analysis of the seismic data;

• the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

• the approval of the prospects by other participants after additional data has been compiled;

• economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;

• our financial resources and results; and

• the availability of leases and permits on reasonable terms for the prospects.

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These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (“FASB”) in Accounting Standards Codification (“ASC”) Section 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.

In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

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Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.

We are continually identifying and evaluating opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.

We face a variety of hazards and risks that could cause substantial financial losses.

Our business involves a variety of operating risks, including:

• blowouts, cratering and explosions;

• mechanical problems;

• uncontrolled flows of natural gas, oil or well fluids;

• formations with abnormal pressures;

• pollution and other environmental risks; and

• natural disasters.

In addition, we conduct operations in shallow offshore areas, which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, impairment of our operations and substantial losses to us.

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures.

We may not be insured against all of the operating risks to which we are exposed.

We maintain insurance coverage against certain, but not all, hazards that could arise from our operations both onshore and offshore. Such insurance is believed to be reasonable for the hazards and risks faced by us. We do not carry business interruption insurance. In addition pollution and environmental risks are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

As of December 31, 2013, we maintain for onshore operations total excess liability insurance with limits of $20 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. Through July 30, 2012, when plugging and abandonment of our operated offshore properties were substantially complete, we also maintained for offshore operations total excess liability insurance with limits of $35 million per occurrence and in the aggregate covering certain general liability and certain “sudden and accidental” environmental risks with a deductible of $10,000 per occurrence, subject to all terms, restrictions and sub-limits of the policies. We also maintain general liability insurance limits of $1 million per occurrence and $2 million in the aggregate for our onshore operations.

We have several policies that cover environmental risks. We have environmental coverage under the per occurrence and aggregate limits of our general and umbrella liability policies (for a twelve-month term). These policies provide third-party surface cleanup, bodily injury and property damage coverage, and defense costs when a pollution event is sudden and accidental and is discovered within thirty days of commencement and reported to the insurance company within ninety days of discovery. This is standard coverage in oil and gas insurance policies.

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We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of limits sufficient to meet the legal financial responsibility requirement of the BSEE as prescribed under the OPA and individual state legal financial responsibility requirements.

Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers and contractors. However, customers and contractors who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

With regard to our offshore operations, generally, indemnities and insurance limits for each contract are negotiated with each of our contractors. Our contracts generally follow the industry standard of providing mutual hold harmless and indemnity agreements, which results in each party being liable or responsible for all claims related to its employees and its contractors, as well as any damage to its and its contractor’s property. Currently, substantially all of our contracts contain mutual hold harmless and indemnity provisions.

From time to time, a small number of our contractors have requested contractual provisions that require us to respond to third-party claims. In some of these instances we have accepted the risk with the understanding that it would be covered under our current coverage. We evaluate these risk-transferring negotiations cautiously, and we feel that we have adequately mitigated this risk through existing coverage or acquiring supplemental coverage when appropriate.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

Bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator

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and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Terrorist activities and the potential for military and other actions could adversely affect our business.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.

We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. These hedging arrangements limit the benefit to us of increases in prices. We will continue to evaluate the benefit of employing derivatives in the future.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

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We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

Item 1B. UNRESOLVED STAFF COMMENTS.

We are a smaller reporting company and therefore no response is required pursuant to this Item.

Item 2. PROPERTIES.

Our executive offices as well as offices of Prime Operating Company, Eastern Oil Well Service Company, EOWS Midland Company and Prime Offshore L.L.C., are located in leased premises in Houston, Texas, and the offices of Southwest Oilfield Construction Company are in Oklahoma City, Oklahoma. We also maintain leased office space at One Landmark Square, Stamford, Connecticut for the administration, accounting and tax preparation for the Partnerships and Trusts.

We maintain district offices in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia, and have field offices in Carrizo Springs and Midland, Texas, Kingfisher and Garvin, Oklahoma and Orma, West Virginia.

Substantially all of our oil and gas properties are subject to a mortgage given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.

The information set forth below concerning our properties, activities, and oil and gas reserves include our interests in affiliated entities.

The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the three years ended December 31, 2013.

	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Exploratory:
Oil		—		—		1		0.42		—		—
Gas		—		—		1		0.50		—		—
Dry		—		—		1		0.03		—		—
Development:
Oil		23		13.60		36		27.96		35		21.98
Gas		—		—		—		—		—		—
Dry		—		—		—		—		1		0.34
Total:
Oil		23		13.60		37		28.38		35		21.98
Gas		—		—		1		0.50		—		—
Dry		—		—		1		0.03		1		0.34
		23		13.60		39		28.91		36		22.32

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Oil and Gas Production

As of December 31, 2013, we had ownership interests in the following numbers of gross and net producing oil and gas wells and gross and net producing acres ⁽¹⁾.

	Gross		Net
Producing wells(1):
Oil Wells		796		399
Gas Wells		956		502
Producing Acres		320,761		110,310

⁽¹⁾  A gross well or gross acre is a well or an acre in which a working interest is owned. A net well or net acre is the sum of the fractional revenue interests owned in gross wells or gross acres. Wells are classified by their primary product. Some wells produce both oil and gas.

The following table shows our net production of oil and natural gas for each of the three years ended December 31, 2013. “Net” production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which we have an interest by percentage of the leasehold, mineral or royalty interest owned by us.

	2013		2012		2011
Oil (barrels)		730,000		745,000		628,000
Gas (Mcf)		4,897,000		4,715,000		5,000,000

The following table sets forth our average sales price per barrel of oil and average sales prices per one thousand cubic feet (“Mcf”) of gas, together with our average production costs per unit of production for the three years ended December 31, 2013.

	2013		2012		2011
Average sales price per barrel	$	90.85	$	90.34	$	92.13
Average sales price per Mcf		5.13		4.45		7.64
Average production costs per net equivalent barrel(1)		25.21		23.14		22.05

⁽¹⁾  Net equivalent barrels are computed at a rate of 6 Mcf per barrel and costs exclude production taxes.

Average oil and gas prices received excluding the impact of derivatives were:

	2013		2012		2011
Oil Price per barrel	$	93.75	$	89.67	$	90.04
Gas Price per Mcf		4.97		4.45		6.38

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Undeveloped Acreage

The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold, mineral and royalty interests as of December 31, 2013. “Undeveloped acreage” is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

	Leasehold Interests				Mineral Interests				Royalty Interests
State	Gross Acres		Net Acres		Gross Acres		Net Acres		Gross Acres		Net Acres
Colorado		—		—		799		23		—		—
Montana		—		—		14,304		60		—		—
Nebraska		—		—		2,554		331		—		—
North Dakota		—		—		640		1		—		—
Oklahoma		880		741		320		—		2,880		24
Texas		5,240		3,719		640		2		—		—
Wyoming		—		—		—		—		140		35
TOTAL		6,120		4,460		19,257		417		3,020		59

Reserves

Our interests, including the interests held by the Partnerships, in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2013. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserves estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Houston Central manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers, geologists and geophysicists and technicians with between approximately ten and thirty-five years of industry experience, and between three and twenty years of experience managing our reserves. Our Houston Central manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over twenty-five years of experience, holds a Bachelor of Science degree in Natural Gas Engineering and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologists. See Part II, Item 8., “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows.

All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:

	Reserve Category
	Proved Developed								Proved Undeveloped								Total
As of December 31,	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)
			(a)				(b)				(a)				(b)				(a)				(b)
2011		6,418				43,631		13,690		2,435				9,765		4,063		8,853				53,396		17,752
2012		7,178		2,909		27,833		14,726		5,907		2,877		12,613		10,886		13,085		5,786		40,446		25,612
2013		6,687		2,223		31,628		14,182		9,066		3,707		19,772		16,068		15,753		5,930		51,400		30,250

(a) Prior to December 31, 2012, natural gas liquids (NGLs) were included in the oil and gas reserve reports under the natural gas heading using a standard conversion factor of one barrel of NGLs to six thousand cubic feet (Mcf) of gas.

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(b) In computing total reserves on a barrels of oil equivalent (Boe), gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.

Our proved undeveloped reserves of 4,063 MBoe as of December 31, 2011 included 64 in-fill drilling locations in our West Texas drilling program and 5 drilling locations in our Mid-Continent region. During 2012 we drilled 29 West Texas wells and 7 Mid-Continent wells at a cost of $42.3 million converting 1,449 MBoe to proved developed producing reserves and added 85 additional proved undeveloped drilling locations. Proved undeveloped reserves of 10,886 MBoe as of December 31, 2012 included 127 drilling locations in our West Texas drilling program, 11 drilling locations in our Mid-Continent region and 2 drilling locations in our Gulf Coast region. During 2013 we drilled 9 West Texas wells and 14 Mid-Continent wells at a cost of $25.9 million converting 913 MBoe to proved developed producing reserves and added 40 additional proved undeveloped drilling locations. Proved undeveloped reserves of 16,068 MBoe as of December 31, 2013 included 148 drilling locations in our West Texas drilling program, 10 drilling locations in our Mid-Continent region and 4 drilling locations in our Gulf Coast region. We have no proved undeveloped reserves scheduled for development five years beyond date of first booking.

We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2013, are summarized as follows (in thousands of dollars):

	Proved Developed				Proved Undeveloped				Total
As of December 31,	Future Net Revenue		Present Value 10 Of Future Net Revenue		Future Net Revenue		Present Value 10 Of Future Net Revenue		Future Net Revenue		Present Value 10 Of Future Net Revenue		Present Value 10 Of Future Income Taxes		Standardized Measure of Discounted Cash flow
2011	$	394,662	$	217,900	$	121,547	$	35,256	$	516,209	$	253,156	$	68,648	$	184,508
2012		380,346		214,533		290,594		73,340		670,940		287,873		74,600		213,273
2013		341,841		204,326		455,622		131,510		797,463		335,836		97,608		238,228

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV 10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV 10 of future income taxes represents the sole reconciling item between this non-GAAP PV 10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves

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that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of our reserves.

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

The range of Henry Hub daily gas prices per MMbtu during the year 2013 was a low of $3.08 and a high of $4.52 and the average was $3.73. The range during the first two months of 2014 has been from $3.95 to $8.15 with an average of $5.32. The recent futures market prices have traded in the range of $5.79 per MMbtu.

The range of NYMEX oil prices per barrel during the year 2013 was a low of $86.65 and a high of $110.62 and the average was $97.98. The range during the first two months of 2014 has been from $91.36 to $103.46 with an average of $97.56. The recent futures market prices have fluctuated around $102.00 per barrel.

While it may reasonably be anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Since January 1, 2014, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

District Information

The following table presents certain reserve, production and well information as of December 31, 2013.

	Appalachian		Gulf Coast		Mid- Continent		West Texas		Other		Total
Proved Reserves at Year End (MBoe)
Developed		1,087		1,030		3,167		8,768		130		14,182
Undeveloped		—		220		269		15,579		—		16,068
Total		1,087		1,250		3,436		24,347		130		30,250
Average Daily Production (Boe per day)		402		675		896		2,209		55		4,236
Gross Wells		725		370		727		577		107		2,506
Net Wells		370		152		257		202		17		998
Gross Operated Wells		496		292		383		380		58		1,609

In several of our regions we operate field service groups to service our operated wells and locations as well as third party operators in the area. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

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Appalachian Region

Our Appalachian activities are concentrated primarily in West Virginia. This region is managed from our office in Charleston, West Virginia. Our assets in this region include a large acreage position and a high concentration of wells. At December 31, 2013, we had 725 wells (370 net), of which 496 wells are operated by us. There are multiple producing intervals that include the Big Lime, Injun, Blue Monday, Weir, Berea, Gordon and Devonian Shale formations at depths primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2013 was 402 Boe. While natural gas production volumes from Appalachian reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of Appalachian reserves is relatively long. At December 31, 2013, we had 1,087 MBoe of proved reserves (substantially all natural gas) in the Appalachian region, constituting 4% of our total proved reserves. We operate a small field service group in this region utilizing one swab rig, one paraffin truck, one saltwater hauling truck and limited excavating equipment to primarily service our own operated wells and locations. As of March 1, 2014 the Appalachian region has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Gulf Coast Region

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in Louisiana, southeast Texas and south Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Marg Tex, Wilcox, Pettit, Glenrose, Woodbine, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. We had 370 wells (152 net) in the Gulf Coast region as of December 31, 2013, of which 292 wells are operated by us. Average daily production in 2013 was 675 Boe. At December 31, 2013, we had 1,250 MBoe of proved reserves (37% oil) in the Gulf Coast region, which represented 4% of our total proved reserves. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing 3 workover rigs, 18 water transport trucks, one saltwater disposal well and several trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third party operators as well as utilized in our own operated wells and locations. As of March 1, 2014 the Gulf Coast region has no wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2013, we had 727 wells (257 net) in the Mid-Continent area, of which 383 wells are operated by us. Principal producing intervals are in the Roberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. Average net daily production in 2013 was 896 Boe. At December 31, 2013, we had 3,436 MBoe of proved reserves (51% oil) in the Mid-Continent area, or 11% of our total proved reserves. We operate a field service group in this region from a field office in Kingfisher, Oklahoma utilizing 4 workover rigs, 2 saltwater hauling trucks and several trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third party operators as well as utilized in our own operated wells and locations. As of March 1, 2014 the Mid-Continent region has one well in the process of being drilled and two wells or awaiting completion, no waterfloods in the process of being installed and no other related activities of material importance.

West Texas Region

Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico. This region is managed from our office in Midland, Texas. As of December 31, 2013, we had 577 wells (202 net) in the West Texas area, of which 380 wells are operated by us. Principal producing intervals are in the Spraberry, Wolfcamp

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and San Andres formations at depths ranging from 5,500 to 12,500 feet. Average net daily production in 2013 was 2,209 Boe. At December 31, 2013, we had 24,347 MBoe of proved reserves (55% oil) in the West Texas area, or 80% of our total proved reserves. We operate a field service group in this region utilizing 8 workover rigs, 3 hot oiler trucks and several trucks. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third party operators as well as utilized in our own operated wells and locations. As of March 1, 2014 the West Texas region has no wells in the process of being drilled and four wells awaiting completion, no waterfloods in the process of being installed and no other related activities of material importance.

Acreage subject to expiration in the next three years;

	2014				2015				2016
State / Area	Gross		Net		Gross		Net		Gross		Net
Texas		—		—		1,640		1,032		—		—
TOTAL		—		—		1,640		1,032		—		—

Item 3. LEGAL PROCEEDINGS.

None.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is listed and principally traded on the NASDAQ Stock Market under the ticker symbol “PNRG”. The following table presents the high and low closing prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system.

	High		Low
2013
First Quarter	$	30.03	$	22.70
Second Quarter		37.00		26.24
Third Quarter		53.25		33.62
Fourth Quarter		51.50		38.11
2012
First Quarter	$	28.55	$	19.19
Second Quarter		27.34		21.43
Third Quarter		28.00		25.01
Fourth Quarter		28.25		22.00

The above quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

As of March 23, 2014, there were 493 registered holders of the common stock.

No dividends have been declared or paid during the past two years on our common stock. Provisions of our line of credit agreement restrict our ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by our Board of Directors.

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Issuer Purchases of Equity Securities

In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012, the Board of Directors of the Company approved an additional 500,000 shares of the Company’s stock to be included in the stock repurchase program. A total of 3,500,000 shares have been authorized, to date, under this program. Through December 31, 2013, a total of 3,157,672 shares have been repurchased under this program for $48,907,683 at an average price of $15.49 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital.

2013 Month	Number of Shares		Average Price Paid per share		Maximum Number of Shares that May Yet Be Purchased Under The Program at Month-End
January		2,712	$	25.06		461,392
February		6,710		26.78		454,682
March		47,219		29.17		407,463
April		15,177		30.38		392,286
May		16,416		31.26		375,870
June		4,069		33.21		371,801
July		2,551		41.69		369,250
August		1,371		46.73		367,879
September		1,457		50.23		366,422
October		6,999		46.69		359,423
November		6,093		47.08		353,330
December		11,002		49.68		342,328
Total / Average		121,776	$	33.98

Item 6. SELECTED FINANCIAL DATA

We are a smaller reporting company and therefore no response is required pursuant to this Item.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Report contains additional information that should be referred to when reviewing this material. Our subsidiaries are listed in Note 1 to the Consolidated Financial Statements.

Overview:

We are an independent oil and natural gas company engaged in acquiring, developing and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia, New Mexico, Colorado and Louisiana. In addition, we own a substantial amount of well servicing equipment. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing hedging program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations and our credit facility.

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which we own interests. We continue to actively pursue the acquisition of producing properties. In order to diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities and companies in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income producing assets so as to build stockholder value through consistent growth in our oil and gas reserve base on a cost-efficient basis.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

Critical Accounting Estimates:

Proved Oil and Gas Reserves

Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.

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Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

Depreciation, depletion and amortization of the cost of proved oil and gas properties are calculated using the unit-of-production method. The reserve base used to calculate depletion, depreciation or amortization is the sum of proved developed reserves and proved undeveloped reserves for leasehold acquisition costs and the cost to acquire proved properties. The reserve base includes only proved developed reserves for lease and well equipment costs, which include development costs and successful exploration drilling costs. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.

Liquidity And Capital Resources:

Net cash provided by operating activities for the year ended December 31, 2013 was $36 million, compared to $40 million in the prior year. Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of derivatives.

If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through additional bank financing.

As of March 1, 2014, the Company maintains a credit facility totaling $250 million, with a borrowing base of $140 million. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

In July 2013, we obtained a $10 million loan secured by most of the field service equipment that we own to conduct our field service operations. We used the funds from that loan to pay down our credit facility, and as a result, freed up additional funds under the credit facility for future acquisitions, development and operations. As of March 20, 2014, we had a total of $8.9 million outstanding on this loan.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. We continued our drilling program in our West Texas and Mid-Continent regions. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zone with a lateral wellbore. During 2014, we intend to drill a total of approximately 20 gross (11 net) wells, primarily in the West Texas area, at a net cost of $60 million. We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. However, the majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

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The Company has in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2013 was $4.2 million. The Company expects continued spending under these programs in 2014.

Results of Operations:

2013 and 2012 Compared

We reported net income for 2013 of $12.27 million, or $5.04 per share. During 2012, we reported net income of $15.06 million, or $5.74 per share. Net income decreased in 2013 by $2.79 million or 18%, primarily due to net decreases in gains from derivative instruments, increased lease operating and field service expenses partially offset by increases in oil and gas sales and field service income and decreased depreciation and depletion expenses. Operating revenues increased by $4.09 million in 2013 as compared to 2012 largely due to a slight increase in net production and increased commodity prices realized in 2013 and an increase in field service income with the addition of new service equipment during 2013 partially offset by losses on derivative instruments in 2013 versus gains on derivative instruments recognized in 2012. Lease operating and field service expenses increased $3.94 million and $3.45 million, respectively, in 2013 as compared to 2012 primarily from increased labor and chemical costs and an increase in services provided. Depreciation and depletion decreased by $1.41 million in 2013 as compared to 2012 primarily associated with offshore properties as our offshore properties were plugged and abandoned during 2012.

The significant components of net income are discussed below.

Oil and gas sales increased $4.96 million, or 6% from $87.83 million for the year ended December 31, 2012 to $92.79 million for the year ended December 31, 2013. Crude oil and natural gas sales vary due to changes in volumes of production sold and realized commodity prices. Our realized prices at the well head increased an average of $4.08 per barrel, or 5% on crude oil and $0.52 per Mcf, or 12% on natural gas during 2013 as compared to 2012.

Our crude oil production decreased by 15,000 barrels, or 2% from 745,000 barrels for the year ended December 31, 2012 to 730,000 barrels for the year ended December 31, 2013. Our natural gas production increased by 182 MMcf, or 4% from 4,715 MMcf for the year ended December 31, 2012 to 4,897 MMcf for the year ended December 31, 2013. The slight decrease in crude oil production volumes are a result of significant disruptions in our production due to the effects of the extreme cold weather in our producing areas — particularly West Texas and Oklahoma and the natural decline of existing properties substantially offset by production from new wells we placed into production from our continued drilling success in West Texas and the Gulf Coast regions. The natural gas volume increases are primarily due to the natural gas production from wells in the West Texas region recently placed into production.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2013 and 2012 (excluding realized gains and losses from derivatives).

	Year Ended December 31,				Increase (Decrease)
	2013		2012		Amount			Percent
Barrels of Oil Produced		730,000		745,000		(15,000	)		(2	)%
Average Price Received (excluding the impact of derivatives)	$	93.75	$	89.67	$	4.08			5	%
Oil Revenue (In 000’s)	$	68,446	$	66,830	$	1,616			2	%
Mcf of Gas Produced		4,897,000		4,715,000		182,000			4	%
Average Price Received (excluding the impact of derivatives)	$	4.97	$	4.45	$	0.52			12	%
Gas Revenue (In 000’s)	$	24,339	$	21,004	$	3,335			16	%
Total Oil & Gas Revenue (In 000’s)	$	92,785	$	87,834	$	4,951			6	%

Realized net gains (losses) on derivative instruments include net losses of $1.3 million on the settlements of crude oil and natural gas derivatives for the year ended December 31, 2013. During 2012, we unwound and

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monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for net proceeds of $1.0 million. The $1.0 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.

Oil and gas prices received including the impact of derivatives but excluding the early settlement transactions were:

	Year Ended December 31,				Increase (Decrease)
	2013		2012		Amount		Percent
Oil Price	$	90.85	$	88.96	$	1.89		2	%
Gas Price	$	5.13	$	4.45	$	0.68		15	%

We do not apply hedge accounting to any of our commodity based derivatives thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the year ended December 31, 2013, we recognized $0.6 million in net unrealized losses. This unrealized loss primarily relates to held crude oil and natural gas fixed swaps and collars associated with future production due to an increase in crude oil and natural gas futures market prices between January 1, 2013 and December 31, 2013.

Field service income increased $4.51 million, or 22% from $20.42 million for the year ended December 31, 2012 to $24.93 million for the year ended December 31, 2013. This underlying increase is a result of adding service equipment and the market allowing us to charge slightly higher rates to customers. Workover rig services represent the bulk of our field service operations, and those rates have all increased between the periods in our most active districts.

Lease operating expense increased $3.94 million, or 10% from $39.87 million for the year ended December 31, 2012 to $43.81 million for the year ended December 31, 2013. This underlying increase is primarily due to higher pumper / labor costs and chemical expenses associated with new wells coming on line from the recent drilling success in West Texas and increased expensed workovers across all districts, partially offset by decreased operating expenses on the offshore properties during 2013.

Field service expense increased $3.45 million, or 20% from $17.58 million for the year ended December 31, 2012 to $21.03 million for the year ended December 31, 2013. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased as a direct result of increased services and utilization of the equipment during the year ended December 31, 2013 as compared to the same period of 2012.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $1.41 million, or 6% from $23.27 million for the year ended December 31, 2012 to $21.86 million for the year ended December 31, 2013. This decrease is primarily due to decreased depletion rates recognized during 2013 associated with offshore properties as our offshore properties were plugged and abandoned during 2012, partially offset by increased depletion expenses related to new wells coming on line from the recent drilling success in West Texas.

General and administrative expense increased $0.79 million, or 5% from $15.87 million for the year ended December 31, 2012 to $16.66 million for the year ended December 31, 2013. This slight increase is largely due to increased personnel costs in 2013. The largest component of these personnel costs was salaries, employee related taxes and insurance.

Gain on sale and exchange of assets of $2.82 million for the year ended December 31, 2013 consists of sales of non-producing acreage and non-core oil and gas interests and non-essential field service equipment

32

whereas the gain on sale and exchange of assets of $0.73 million for the year ended December 31, 2012 consists of sales of non-essential field service equipment.

Interest expense increased $0.64 million, or 18% from $3.58 million for the year ended December 31, 2012 to $4.22 million for the year ended December 31, 2013. This increase relates to an increase in average debt outstanding during 2013 as compared to 2012 slightly offset by a decrease in weighted average interest rates during the 2013 periods. The average interest rate paid on outstanding bank borrowings subject to interest during 2013 and 2012 were 3.58% and 3.81%, respectively. As of December 31, 2013 and 2012, the total outstanding borrowings were $121.89 million and $122.00 million, respectively.

A provision for income taxes of $6.82 million, or an effective tax rate of 36% was recorded for the year ended December 31, 2013 verses a provision of $6.86 million, or an effective tax rate of 31% for the year ended December 31, 2012. Our provision for income taxes varies from the federal statutory tax rate of 34% primarily due to percentage depletion. We are entitled to percentage depletion on certain of our wells for tax purposes, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis it creates a permanent difference, which lowers our effective rate.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are a smaller reporting company and therefore no response is required pursuant to this Item.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

The consolidated financial statements and supplementary information included in this Report are described in the Index to Consolidated Financial Statements at Page F-1 of this Report.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

Item 9A. CONTROLS AND PROCEDURES.

As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”). Disclosure Controls, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and

33

there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15 or 15d-15, as of December 31, 2013, the end of the period covered by this Report. Based upon that evaluation, these officers concluded that our disclosure controls and procedures were effective as of December 31, 2013.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2013.

This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report.

There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. OTHER INFORMATION.

None.

34

PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Information relating to the Company’s Directors, nominees for Directors and executive officers will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in May, 2014 which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2013, and which is incorporated herein by reference.

Item 11. EXECUTIVE COMPENSATION.

Information relating to executive compensation will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2014, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2013, and which is incorporated herein by reference.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

Information relating to security ownership of certain beneficial owners and management will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2014, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2013, and which is incorporated herein by reference.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

Information relating to certain transactions by Directors and executive officers of the Company will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2014, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2013, and which is incorporated herein by reference.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Information relating to principal accountant fees and services will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in May, 2014, which will be filed with the U. S. Securities and Exchange Commission within 120 days of December 31, 2013, and which is incorporated herein by reference.

35

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

The following documents are filed as part of this Report:

1. Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report)

2. Financial Statement Schedules (Index to Consolidated Financial Statements—Supplementary Information at page F-1 of this Report)

3. Exhibits:

Exhibit No.
3.1	Restated Certificate of Incorporation of PrimeEnergy Corporation (effective July 1, 2009) (Incorporated by reference to Exhibit 3.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2009).
3.2	Bylaws of PrimeEnergy Corporation (Incorporated by reference to Exhibit 3.2 of PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010).
10.4	Amended and Restated Agreement of Limited Partnership, FWOE Partners L.P., dated as of August 22, 2005 (Incorporated by reference to Exhibit 10.3 of PrimeEnergy Corporation Form 8-K for events of August 22, 2005).
10.4.1	Contribution Agreement between F-W Oil Exploration L.L.C. and FWOE Partners L.P. dated as of August 22, 2005 (Incorporated by reference to exhibit 10.4 of PrimeEnergy Corporation Form 8-K for events of August 22, 2005).
10.18	Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Corporation Form 10-K for the year ended December 31, 2004).
10.22.5.9	Second Amended and Restated Credit Agreement dated July 30, 2010, by and among PrimeEnergy Corporation, the Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, and EOWS Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB) As Administrative Agent and Letter of Credit Issuer, BBVA Compass, As Sole Lead Arranger and Sole Bookrunner and The Lenders Signatory Hereto (BNP Paribas, JPMorgan Chase Bank, N.A. and Amegy Bank National Association) (Incorporated by reference to Exhibit 10.22.5.9 of PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2010).
10.22.5.9.1	First Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective September 30, 2010 (Incorporated by reference to Exhibit 10.22.5.9.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2010).
10.22.5.9.2	Second Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective June 22, 2011 (Incorporated by reference to Exhibit 10.22.5.9.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2011).

36

Exhibit No.
10.22.5.9.3	Third Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective December 8, 2011 (Incorporated by reference to Exhibit 10.22.5.9.3 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2011).
10.22.5.9.4	Fourth Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, BNP Paribas, JPMorgan Chase Bank, N.A., Amegy Bank National Association) effective June 25, 2012 (Incorporated by reference to Exhibit 10.22.5.9.4 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2012).
10.22.5.9.5	Fifth Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company, Prime Offshore L.L.C.), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., Amegy Bank National Association, KeyBank National Association) effective November 26, 2012 (Incorporated by reference to Exhibit 10.22.5.9.5 to PrimeEnergy Corporation Form 10-K for the year ended December 31, 2012).
10.22.5.9.6	Sixth Amendment To Second Amended and Restated Credit Agreement Among PrimeEnergy Corporation, The Guarantors Party Hereto (PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well Service Company, Southwest Oilfield Construction Company, E O W S Midland Company, Prime Offshore L.L.C.), Compass Bank (successor in interest to Guaranty Bank, FSB), As Administrative Agent, Letter of Credit Issuer and Collateral Agent and The Lenders Signatory Hereto (Compass Bank, Wells Fargo Bank National Association, JPMorgan Chase Bank, N.A., Amegy Bank National Association, KeyBank National Association) effective June 28, 2013 (Incorporated by reference to Exhibit 10.22.5.9.6 to PrimeEnergy Corporation Form 10-Q for the quarter ended June 30, 2013).
10.22.5.9.7	Assignment Agreement made by and among Amegy Bank National Association, as Assignor, and Compass Bank (successor in interest to Guaranty Bank, FSB), Wells Fargo Bank, National Association, JPMorgan Chase Bank and KeyBank National Association, as Assignees, effective December 23, 2013 (filed herewith).
10.23.1	Loan and Security Agreement dated July 31, 2013, by and between JP Morgan Chase Bank, N.A. and Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company (Incorporated by reference to Exhibit 10.23.1 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).
10.23.2	Business Purpose Promissory Note dated July 31, 2013, made by Eastern Oil Well Service Company, EOWS Midland Company and Southwest Oilfield Construction Company to JP Morgan Chase Bank N.A. (Incorporated by reference to Exhibit 10.23.2 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).

37

Exhibit No.
10.23.3	Guaranty dated July 31, 2013, made by PrimeEnergy Corporation in favor of JP Morgan Chase Bank, N.A. Incorporated by reference to Exhibit 10.23.3 to PrimeEnergy Corporation Form 10-Q for the quarter ended September 30, 2013).
14	PrimeEnergy Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Corporation Form 10-K for the year ended December 31, 2011).
21	Subsidiaries (filed herewith).
23	Consent of Ryder Scott Company, L.P. (filed herewith).
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
99.1	Summary Reserve Report dated March 7, 2014, of Ryder Scott Company, L.P. (filed herewith).
101.INS	XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)
101.SCH	XBRL Taxonomy Extension Schema Document (filed herewith)
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)
101.LAB	XBRL Taxonomy Extension Label Linkbase Document (filed herewith)
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

38

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25^th day of March, 2014

PrimeEnergy Corporation
By:	/s/ CHARLES E. DRIMAL, JR.
	Charles E. Drimal, Jr.
	Chairman, Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 25^th day of March, 2014.

/s/ CHARLES E. DRIMAL, JR. Charles E. Drimal, Jr.	Chairman, Chief Executive Officer and President; The Principal Executive Officer
/s/ BEVERLY A. CUMMINGS Beverly A. Cummings	Director, Executive Vice President and Treasurer; The Principal Financial Officer

/s/ MATTHIAS ECKENSTEIN	Director	/s/ CLINT HURT	Director
Matthias Eckenstein		Clint Hurt
/s/ H. GIFFORD FONG	Director	/s/ JAN K. SMEETS	Director
H. Gifford Fong		Jan K. Smeets
/s/ THOMAS S.T. GIMBEL	Director
Thomas S.T. Gimbel

39

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Financial Statements
Consolidated Balance Sheet—As of December 31, 2013 and 2012	F-3
Consolidated Statement of Operations—For the years ended December 31, 2013 and 2012	F-4
Consolidated Statement of Comprehensive Income—For the years ended December 31, 2013 and  2012	F-5
Consolidated Statement of Equity—For the years ended December 31, 2013 and 2012	F-6
Consolidated Statement of Cash Flows—For the years ended December 31, 2013 and 2012	F-7
Notes to Consolidated Financial Statements	F-8
Supplementary Information:
Capitalized Costs Relating to Oil and Gas Producing Activities, years ended December  31, 2013 and 2012	F-21
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities, years ended December 31, 2013 and 2012	F-21
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas  Reserves, years ended December 31, 2013 and 2012	F-21
Standardized Measure of Discounted Future Net Cash Flows and  Changes Therein Relating to Proved Oil and Gas Reserves, years ended December 31, 2013 and 2012	F-22
Reserve Quantity Information, years ended December 31, 2013 and 2012	F-23
Results of Operations from Oil and Gas Producing Activities, years ended December 31, 2013 and 2012	F-23
Notes to Supplementary Information	F-24

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

PrimeEnergy Corporation and Subsidiaries:

We have audited the accompanying consolidated balance sheets of PrimeEnergy Corporation and Subsidiaries (the Company) as of December 31, 2013 and 2012, and related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years then ended. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of PrimeEnergy Corporation and Subsidiaries as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Grassi & Co., CPAs, P.C.

GRASSI & CO., CPAs, P.C.

New York, New York

March 20, 2014

F-2

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Thousands of dollars)

	As of December 31,
	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	9,526		$	8,602
Restricted cash and cash equivalents		2,065			4,672
Accounts receivable, net		17,693			13,212
Prepaid obligations		1,188			1,656
Derivative contracts		357			1,229
Other current assets		1,846			1,081
Total Current Assets		32,675			30,452
Property and Equipment
Oil and gas properties at cost		364,123			338,204
Less: Accumulated depletion and depreciation		(169,100	)		(150,276	)
		195,023			187,928
Field and office equipment at cost		26,653			23,974
Less: Accumulated depreciation		(13,251	)		(15,052	)
		13,402			8,922
Total Property and Equipment, Net		208,425			196,850
Derivative Contracts Long-Term		1,066			118
Other Assets		756			666
Total Assets	$	242,922		$	228,086
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	16,249		$	19,568
Accrued liabilities		6,832			7,618
Current portion of long-term debt		1,870			—
Current portion of asset retirement and other long-term obligations		3,310			2,148
Derivative liability short-term		2,194			994
Due to related parties		23			67
Total Current Liabilities		30,478			30,395
Long-Term Bank Debt		120,023			122,000
Asset Retirement Obligations		7,227			6,864
Derivative Liability Long-Term		94			431
Deferred Income Taxes		31,962			24,194
Total Liabilities		189,784			183,884
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2013 and 2012: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2013: 2,388,784 shares; 2012: 2,510,560 shares		383			383
Paid-in capital		6,803			6,690
Retained earnings		78,616			66,345
Accumulated other comprehensive loss, net		(123	)		(35	)
Treasury stock, at cost; 2013: 1,447,613 shares; 2012: 1,325,837 shares		(40,251	)		(36,113	)
Total Stockholders’ Equity—PrimeEnergy		45,428			37,270
Non-controlling interest		7,710			6,932
Total Equity		53,138			44,202
Total Liabilities and Equity	$	242,922		$	228,086

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-3

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Thousands of dollars, except per share amounts)

	For the Year Ended December 31,
	2013			2012
Revenues
Oil and gas sales	$	92,785		$	87,834
Realized gain (loss) on derivative instruments, net		(1,322	)		502
Field service income		24,934			20,421
Administrative overhead fees		9,255			8,585
Unrealized gain (loss) on derivative instruments		(649	)		3,483
Other income		64			154
Total Revenues		125,067			120,979
Costs and Expenses
Lease operating expense		43,809			39,868
Field service expense		21,027			17,576
Depreciation, depletion, amortization and accretion on discounted liabilities		21,861			23,269
Loss on settlement of asset retirement obligations		40			—
General and administrative expense		16,659			15,870
Exploration costs		8			10
Total Costs and Expenses		103,404			96,593
Gain on Sale and Exchange of Assets		2,816			730
Income from Operations		24,479			25,116
Other Income and Expenses
Less: Interest expense		4,223			3,577
Add: Interest income		2			91
Income Before Provision for Income Taxes		20,258			21,630
Provision for Income Taxes		6,818			6,856
Net Income		13,440			14,774
Less: Net Income (Loss) Attributable to Non-Controlling Interest		1,169			(282	)
Net Income Attributable to PrimeEnergy	$	12,271		$	15,056
Basic Income Per Common Share	$	5.04		$	5.74
Diluted Income Per Common Share	$	3.86		$	4.48

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-4

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Thousands of dollars)

	For the Year Ended December 31,
	2013			2012
Net income	$	13,440		$	14,774
Other Comprehensive Loss, net of taxes:
Changes in fair value of hedge positions, net of taxes of $50 and $19, respectively		(88	)		(35	)
Total other comprehensive loss		(88	)		(35	)
Comprehensive income		13,352			14,739
Less: Comprehensive income (loss) attributable to non-controlling interest		1,169			(282	)
Comprehensive income attributable to PrimeEnergy	$	12,183		$	15,021

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-5

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF EQUITY

(Thousands of dollars)

	Common Stock				Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Loss			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non-Controlling Interest			Total Equity
	Shares		Amount
Balance at December 31, 2011		3,836,397	$	383	$	6,446	$	51,289	$	—		$	(31,120	)	$	26,998		$	8,755		$	35,753
Purchase 191,309 shares of common stock		—		—		—		—		—			(4,993	)		(4,993	)		—			(4,993	)
Net income		—		—		—		15,056		—			—			15,056			(282	)		14,774
Other comprehensive loss, net of taxes		—		—		—		—		(35	)		—			(35	)		—			(35	)
Purchase of non-controlling interest		—		—		244		—		—			—			244			(393	)		(149	)
Distributions to non-controlling interest		—		—		—		—		—			—			—			(1,148	)		(1,148	)
Balance at December 31, 2012		3,836,397	$	383	$	6,690	$	66,345	$	(35	)	$	(36,113	)	$	37,270		$	6,932		$	44,202
Purchase 121,776 shares of common stock		—		—		—		—		—			(4,138	)		(4,138	)		—			(4,138	)
Net income		—		—		—		12,271		—			—			12,271			1,169			13,440
Other comprehensive loss, net of taxes		—		—		—		—		(88	)		—			(88	)		—			(88	)
Purchase of non-controlling interest		—		—		113		—		—			—			113			(161	)		(48	)
Distributions to non-controlling interest		—		—		—		—		—			—			—			(230	)		(230	)
Balance at December 31, 2013		3,836,397	$	383	$	6,803	$	78,616	$	(123	)	$	(40,251	)	$	45,428		$	7,710		$	53,138

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-6

PRIMEENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of dollars)

	For the Year Ended December 31,
	2013			2012
Cash Flows from Operating Activities:
Net income	$	13,440		$	14,774
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		21,861			23,269
Gain on sale of properties		(2,816	)		(730	)
Unrealized (gain) loss on derivative instruments		649			(3,483	)
Provision for deferred income taxes		7,014			6,970
Loss on settlement of asset retirement obligations		40			—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(4,481	)		3,294
Increase in due from related parties		(96	)		(25	)
(Increase) decrease in inventories		91			(2	)
Decrease in prepaid expenses and other assets		378			5,761
Decrease in accounts payable		(712	)		(9,500	)
Increase (decrease) in accrued liabilities		332			(616	)
Net Cash Provided by Operating Activities		35,700			39,712
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense		(33,934	)		(86,305	)
Proceeds from sale of properties and equipment		3,681			881
Net Cash Used in Investing Activities		(30,253	)		(85,424	)
Cash Flows from Financing Activities:
Purchase of stock for treasury		(4,138	)		(4,993	)
Purchase of non-controlling interests		(48	)		(149	)
Increase in long-term bank debt and other long-term obligations		68,750			111,800
Repayment of long-term bank debt and other long-term obligations		(68,857	)		(59,857	)
Distribution to non-controlling interest		(230	)		(1,148	)
Net Cash (Used in) Provided by Financing Activities		(4,523	)		45,653
Net Increase (Decrease) in Cash and Cash Equivalents		924			(59	)
Cash and Cash Equivalents at the Beginning of the Year		8,602			8,661
Cash and Cash Equivalents at the End of the Year	$	9,526		$	8,602
Supplemental Disclosures:
Income taxes paid during the year	$	754		$	536
Interest paid during the year	$	4,183		$	3,535

The accompanying Notes are an integral part of these Consolidated Financial Statements

F-7

PRIMEENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Operations and Significant Accounting Policies

Nature of Operations:

PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico. The Company operates approximately 1,600 wells and owns non-operating interests in over 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PEC owns Eastern Oil Well Service Company (“EOWSC”), EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”). The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.

Consolidation and Presentation:

The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.

Reclassifications:

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.

F-8

Subsequent Events:

Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.

Use of Estimates:

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.

Property and Equipment:

The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.

Capitalization of Interest:

Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.

Impairment of Long-Lived Assets:

The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

Fair Value:

The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be

F-9

received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

Asset Retirement Obligation:

The Company follows the accounting standard for asset retirement obligation. The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.

Income Taxes:

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

General and Administrative Expenses:

General and administrative expenses represent cost and expenses associated with the operation of the Company.

Earnings Per Common Share:

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods.

F-10

Statements of Cash Flows:

For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.

Concentration of Credit Risk:

The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.

Hedging:

The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2013 and 2012, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations.

Recently Adopted Accounting Standards:

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities.” This ASU requires enhanced disclosures including both gross and net information about financial and derivative instruments eligible for offset or subject to an enforceable master netting arrangement or similar agreement. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 clarifies the scope of ASU 2011-11 to apply to derivative instruments that are offset or subject to an enforceable master netting arrangement or similar agreement. This clarified guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. The revised requirements of ASU 2011-11 and ASU 2013-01 impacted the disclosures associated with the Company’s derivative instruments (Note 11) and did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“AOCI”). ASU 2013-02 requires a rollforward of changes in AOCI by component and information about significant reclassifications from AOCI to net earnings to be presented in one location, either on the face of the financial statements or in the notes. This new guidance is effective for fiscal years beginning after December 15, 2012 and subsequent interim periods. There was no amounts reclassified out of accumulated other comprehensive income for the year ended December 31, 2013. The requirements of ASU 2013-02 did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.

F-11

In July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

2. Acquisitions and Dispositions

Historically, the Company has repurchased the noncontrolling interests of the partners and trust unit holders in certain of the Partnerships, which consist primarily of oil and gas interests. The Company purchased such noncontrolling interests in an amount totaling $48,000 in 2013 and $149,000 in 2012.

3. Additional Balance Sheet Information

Accounts receivable at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013			2012
Joint interest billings	$	6,287		$	2,189
Trade receivables		2,014			1,580
Oil and gas sales		9,604			9,362
Other		122			436
		18,027			13,567
Less: Allowance for doubtful accounts		(334	)		(355	)
Total	$	17,693		$	13,212

Accounts payable at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013		2012
Trade	$	1,596	$	3,968
Royalty and other owners		7,391		9,652
Partner advances		3,378		3,589
Prepaid drilling deposits		978		306
Other		2,906		2,053
Total	$	16,249	$	19,568

Accrued liabilities at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013		2012
Compensation and related expenses	$	3,062	$	2,517
Property costs		3,119		4,549
Income tax		268		—
Other		383		552
Total	$	6,832	$	7,618

F-12

4. Property and Equipment

Capitalized interest is included as part of the cost of oil and gas properties. The capitalized rates are based upon the Company’s weighted-average cost of borrowings used to finance the expenditures. There was no interest capitalized during 2013 or 2012.

5. Long-Term Debt

Bank Debt:

Effective July 30, 2010, the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement has a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be redetermined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.

The Credit Agreement has been amended from time to time to further define the limitations on loans or advances and investments made in the Company’s limited partnerships; modify the Company’s borrowing base and monthly reduction amounts; remove the floor rate component of LIBO rate loans; modify financial reporting requirements to the agent; increase hedging allowances; allow for a one-time advance to be made to the Company’s offshore subsidiary; and amend restrictions on the payments for dividends, distributions or repurchase of PEC’s stock.

The Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

Under the Credit Agreement, the maximum percentage of production available to enter into commodity hedge agreements is 90% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, the Company’s restrictions on the payment of dividends, distributions or purchase of treasury stock is limited to an aggregate of $5.0 million in each calendar year.

At December 31, 2013, the credit facility borrowing base was $140.0 million with no monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at December 31, 2013) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.50% to 3.00%. At December 31, 2013, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.92%, respectively.

At December 31, 2013, the Company had $112.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.06%, and $27.5 million available for future borrowings.

F-13

The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.58% for the year ended December 31, 2013, as compared to 3.81% for the year ended December 31, 2012.

The Company has entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commence in January 2014, related to $75 million of the Company’s bank debt resulting in a fixed rate of 0.563% plus the Company’s current applicable margin.

Equipment Loan:

On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by substantially all of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of December 30, 2013, the Company had a total of $9.4 million outstanding on the Equipment Loan.

6. Commitments

Operating Leases:

The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the operating leases at December 31, 2013 are as follows.

(Thousands of dollars)	Operating Leases
2014	$	747
2015		651
2016		545
2017		46
Total minimum payments	$	1,989

Rent expense for office space for the years ended December 31, 2013 and 2012 was $699,000 and $755,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2013 and 2012 is as follows:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Asset retirement obligation at beginning of period	$	9,012		$	19,013
Liabilities incurred		338			733
Loss on settlement of obligations		40			—
Liabilities settled		(776	)		(15,361	)
Accretion expense		394			1,053
Revisions in estimated liabilities		1,529			3,574
Asset retirement obligation at end of period	$	10,537		$	9,012

F-14

The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. During 2013 and 2012 revisions in estimated liabilities for asset retirement obligation resulted primarily from the enactment of new federal regulation requirements for plugging and abandonment.

7. Contingent Liabilities

The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. At December 31, 2013, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities, and the Company believes these reserves will be sufficient to satisfy Partnership obligations.

The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

8. Stock Options and Other Compensation

In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At December 31, 2013 and 2012, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

9. Income Taxes

The components of the provision (benefit) for income taxes for the years ended December 31, 2013 and 2012 are as follows:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Current:
Federal	$	(462	)	$	16
State		266			(130	)
Total current		(196	)		(114	)
Deferred:
Federal		6,549			7,009
State		465			(39	)
Total deferred		7,014			6,970
Total income tax provision	$	6,818		$	6,856

F-15

The components of net deferred tax assets and liabilities are as follows:

	At December 31,
(Thousands of dollars)	2013		2012
Current Assets:
Accrued liabilities	$	683	$	613
Allowance for doubtful accounts		118		124
Derivative contracts		677		(83	)
Total current deferred income tax assets	$	1,478	$	654
Non-Current Assets:
Alternative minimum tax credits	$	5,852	$	5,890
Net operating loss carry-forwards		168		114
Percentage depletion carry-forwards		4,543		4,287
Derivative contracts		—		91
Total non-current assets		10,563		10,382
Non-Current Liabilities:
Basis differences relating to managed partnerships		2,462		1,492
Depletion and depreciation		39,694		33,084
Derivative contracts		369		—
Total non-current liabilities		42,525		34,576
Net non-current deferred income tax liabilities	$	31,962	$	24,194

The total provision for income taxes for the years ended December 31, 2013 and 2012 varies from the federal statutory tax rate as a result of the following:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Expected tax expense	$	6,491		$	7,450
State income tax, net of federal benefit		488			(112	)
Percentage depletion		(422	)		(902	)
Other, net		261			420
Total income tax provision	$	6,818		$	6,856

The Company showed a net operating loss on its 2012 federal income tax return, which was carried back to the 2010 and 2011 tax years, resulting in total refunds of $685,000. The net operating loss and related refunds were the result of elections to deduct intangible drilling costs in 2012 which was made upon filing the return in 2013, and the refunds result in the lowering of the current federal income tax expense in 2013.

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Differences relating to oil and gas properties owned through Prime Offshore are reflected under “Depletion and depreciation,” while basis differences relating to the managed partnerships are reflected under “Basis differences relating to managed partnerships.”

The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate.

F-16

The Company has $5.9 million in alternative minimum tax (“AMT”) credits which can be used to lower the regular tax liability to the tentative AMT amount in years where the tentative AMT amount is less. These credits do not expire.

The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, and 2009 federal income tax returns have been audited by the Internal Revenue Service, while the 2010, 2011 and 2012 returns remain open for examination. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. State returns for the years 2010, 2011 and 2012 remain open for examination by the relevant taxing authorities.

10. Segment Information and Major Customers

The Company operates in one industry—oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States.

The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company’s total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company’s oil and gas sales in the year 2013.

Oil Purchasers:			Gas Purchasers:
Plains All American Inc.	52	%	Atlas Pipeline Mid-Continent	40	%
Sunoco, Inc.	28	%	Unimark LLC	13	%

Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers.

11. Financial Instruments

Fair Value Measurements:

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2013 and 2012:

December 31, 2013 (Thousands of dollars)	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2013
Assets
Commodity derivative contracts	$	—	$	—	$	1,337		$	1,337
Interest rate derivative contracts		—		—		86			86
Total assets	$	—	$	—	$	1,423		$	1,423
Liabilities
Commodity derivative contracts	$	—	$	—	$	(2,010	)	$	(2,010	)
Interest rate derivative contracts		—		—		(278	)		(278	)
Total liabilities	$	—	$	—	$	(2,288	)	$	(2,288	)

F-17

December 31, 2012 (Thousands of dollars)	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2012
Assets
Commodity derivative contracts	$	—	$	—	$	1,347		$	1,347
Total assets	$	—	$	—	$	1,347		$	1,347
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,371	)	$	(1,371	)
Interest rate derivative contracts		—		—		(54	)		(54	)
Total liabilities	$	—	$	—	$	(1,425	)	$	(1,425	)

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012.

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Net liabilities at beginning of period	$	(78	)	$	(3,507	)
Total realized and unrealized (gains) losses:
Included in earnings(a)		(1,971	)		3,985
Included in other comprehensive loss		(138	)		(54	)
Purchases, sales, issuances and settlements		1,322			(502	)
Net liabilities at end of period	$	(865	)	$	(78	)

^(a)  Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as a reduction to interest expense.

Derivative Instruments:

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.

Interest rate swap derivatives continue to be treated as cash-flow hedges and are used to fix or float interest rates on existing debt. The value of these interest rate swaps at December 31, 2013 is located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, currently scheduled to begin in January 2014, will be recorded within interest expense.

F-18

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2013 and 2012:

		Fair Value at December 31,
(Thousands of dollars)	Balance Sheet Location	2013			2012
Asset Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Other assets	$	86		$	—
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative contracts		307			189
Natural gas commodity contracts	Derivative contracts		50			1,040
Crude oil commodity contracts	Other assets		980			118
Total		$	1,423		$	1,347
Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Derivative liability short-term	$	(209	)	$	—
Interest rate swap contracts	Derivative liability long-term		(69	)		(54	)
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term		(1,667	)		(994	)
Natural gas commodity contracts	Derivative liability short-term		(318	)		—
Crude oil commodity contracts	Derivative liability long-term		(25	)		(377	)
Total		$	(2,288	)	$	(1,425	)
Total derivative instruments		$	(865	)	$	(78	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2013 and 2012:

(Thousands of dollars)	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
		2013			2012
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net	$	(1,309	)	$	1,040
Crude oil commodity contracts	Unrealized gain on derivative instruments, net		660			2,443
Natural gas commodity contracts(a)	Realized gain on derivative instruments, net		796			—
Crude oil commodity contracts(a)	Realized gain (loss) on derivative instruments, net		(2,118	)		502
		$	(1,971	)	$	3,985

^(a)  In January 2012, March 2012 and May 2012, the Company unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for aggregated net proceeds of $1.03 million. The $1.03 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.

F-19

12. Related Party Transactions

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in an amount totaling $48,000 during 2013 and $149,000 during 2012.

Treasury stock purchases in any reported period may include shares from a related party. In April 2012, the Company purchased 45,179 shares of common stock as treasury shares from a Director for $1.13 million. In December 2013, the Company purchased 4,500 shares of common stock as treasury shares from a Director for $222,750. There were no other related party treasury stock purchases during the years ended December 31, 2013 and 2012.

Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.

13. Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents include $2.01 million and $4.44 million at December 31, 2013 and 2012, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at December 31, 2013 and 2012 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying consolidated balance sheets.

14. Salary Deferral Plan

The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions of which $525,000 and $463,000 were made in 2013 and 2012, respectively.

15. Earnings per Share

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:

	Year Ended December 31,
	2013						2012
	Net Income (In  000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In  000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	12,271		2,436,821	$	5.04	$	15,056		2,624,335	$	5.74
Effect of dilutive securities:
Options		—		746,085				—		735,244
Diluted	$	12,271		3,182,906	$	3.86	$	15,056		3,359,579	$	4.48

16. Shareholder’s Equity

The Company has in place a stock repurchase program whereby it may purchase outstanding shares of its common stock from time-to-time, in open market transactions or negotiated sales. The Company uses the cost method to account for its treasury share purchases.

F-20

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

CAPITALIZED COSTS RELATING TO

OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
(Thousands of dollars)	2013		2012
Proved Developed oil and gas properties	$	362,186	$	336,135
Proved Undeveloped oil and gas properties		1,937		2,069
Unproved oil and gas properties		—		—
Total Capitalized Costs		364,123		338,204
Accumulated depreciation, depletion and valuation allowance		169,100		150,276
Net Capitalized Costs	$	195,023	$	187,928

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,

EXPLORATION AND DEVELOPMENT ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited)

	Year Ended December 31,
(Thousands of dollars)	2013		2012
Acquisition of Properties, Developed	$	7	$	6,482
Acquisition of Properties, Undeveloped		—		2,030
Exploration Costs		8		10
Development Costs		25,912		66,671

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
(Thousands of dollars)	2013			2012
Future cash inflows	$	1,880,389		$	1,524,137
Future production costs		(769,172	)		(673,629	)
Future development costs		(313,754	)		(179,568	)
Future income tax expenses		(234,191	)		(186,072	)
Future Net Cash Flows		563,272			484,868
10% annual discount for estimated timing of cash flows		(325,044	)		(271,595	)
Standardized Measure of Discounted Future Net Cash Flows	$	238,228		$	213,273

See accompanying Notes to Supplementary Information

F-21

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS AND CHANGES THEREIN

RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2013 and 2012

(Unaudited)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2013 and 2012:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Sales of oil and gas produced, net of production costs	$	(48,976	)	$	(48,673	)
Net changes in prices and production costs		(10,149	)		504
Extensions, discoveries and improved recovery		218,648			164,557
Revisions of previous quantity estimates		(733	)		40,964
Net change in development costs		(129,672	)		(145,382	)
Reserves sold		—			—
Reserves purchased		—			6,563
Accretion of discount		21,327			18,451
Net change in income taxes		(23,007	)		(5,952	)
Changes in production rates (timing) and other		(2,483	)		(2,267	)
Net change		24,955			28,765
Standardized measure of discounted future net cash flow:
Beginning of year		213,273			184,508
End of year	$	238,228		$	213,273

See accompanying Notes to Supplementary Information

F-22

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

RESERVE QUANTITY INFORMATION

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
	2013									2012
	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)		Gas (MMcf)
Proved Developed Reserves:
Beginning of year		7,178			2,909			27,833			6,418			—		43,631
Extensions, discoveries and improved recovery		87			—			402			224			49		1,000
Revisions of previous estimates		(361	)		(712	)		6,456			252			2,860		(15,821	)
Converted from undeveloped reserves		513			199			1,207			861			—		3,527
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			168			—		211
Production		(730	)		(173	)		(4,270	)		(745	)		—		(4,715	)
End of year		6,687			2,223			31,628			7,178			2,909		27,833
Proved Undeveloped Reserves:
Beginning of year		5,907			2,877			12,613			2,435			—		9,765
Extensions, discoveries and improved recovery		4,536			1,541			9,538			3,446			1,401		6,158
Revisions of previous estimates		864			(512	)		(1,172	)		887			1,476		217
Converted to developed reserves		(513	)		199			(1,207	)		(861	)		—		(3,527	)
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			—			—		—
End of year		9,066			3,707			19,772			5,907			2,877		12,613
Total Proved Reserves at the End of the Year		15,753			5,930			51,400			13,085			5,786		40,446

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited) 

	Year Ended December 31,
(Thousands of dollars)	2013		2012
Revenue:
Oil and gas sales	$	92,785	$	88,336
Costs and Expenses:
Lease operating expenses		43,809		39,868
Exploration costs		8		10
Depreciation, depletion and accretion		19,218		19,883
Income tax expense		10,012		8,941
Total Costs and Expenses		73,047		68,702
Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	19,738	$	19,634

See accompanying Notes to Supplementary Information

F-23

PRIMEENERGY CORPORATION AND SUBSIDIARIES

NOTES TO SUPPLEMENTARY INFORMATION

(Unaudited)

1. Presentation of Reserve Disclosure Information

Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.

2. Determination of Proved Reserves

The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward of downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

3. Results of Operations from Oil and Gas Producing Activities

The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.

4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.

Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.

Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.

F-24

Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.

5. Changes in Reserves

The 2013 and 2012 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

F-25

EX-10.22.5.9.7

Exhibit 10.22.5.9.7

ASSIGNMENT AGREEMENT

THIS ASSIGNMENT AGREEMENT (as amended, supplemented, restated or otherwise modified from time to time, this “Agreement”) is dated as of the Assignment Date (as such term is defined hereinafter), by and among AMEGY BANK NATIONAL ASSOCIATION, a national banking association (“Assignor”), COMPASS BANK (successor in interest to Guaranty Bank, FSB) (“Compass”), WELLS FARGO BANK, NATIONAL ASSOCIATION (“Wells”), JPMORGAN CHASE BANK, N.A. (“JPMC”), and KEYBANK NATIONAL ASSOCIATION (“KeyBank”, and Compass, Wells, JPMC and KeyBank, collectively, the “Assignees”).

RECITALS

WHEREAS, Assignor is a party to the Second Amended and Restated Credit Agreement dated effective July 30, 2010, as amended by that certain First Amendment to Second Amended and Restated Credit Agreement dated effective September 30, 3010, that certain Second Amendment to Second Amended and Restated Credit Agreement dated effective June 22, 2011, that certain Third Amendment to Second Amended and Restated Credit Agreement dated effective December 8, 2011, that certain Fourth Amendment to Second Amended and Restated Credit Agreement dated effective June 25, 2012, that certain Fifth Amendment to Second Amended and Restated Credit Agreement dated effective November 26, 2012, and that certain Sixth Amendment to Second Amended and Restated Credit Agreement dated effective June 28, 2013 (as amended, supplemented, restated or otherwise modified from time to time, the “Credit Agreement”), by and among PrimeEnergy Corporation (the “Borrower”), certain other parties, each of the lenders that is or becomes a party thereto as provided in Section 9.1(b) of the Credit Agreement (individually, together with its successors and assigns, a “Lender”, and collectively, together with their successors and assigns, the “Lenders”), and Compass, as agent for the Lenders and certain other parties under certain circumstances (in such capacity, together with its successors in such capacity, the “Agent”); and

WHEREAS, Assignor proposes to sell, assign and transfer to the Assignees, and each of the Assignees proposes to purchase and assume from Assignor, that portion of Assignor’s Facility Amount and its outstanding Loans set forth herein for the relevant Assignee, all on the terms and conditions of this Agreement;

NOW, THEREFORE, in consideration of the foregoing and the mutual agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS AND INTERPRETATION

1.1 Definitions from Credit Agreement. All capitalized terms used but not defined herein have the respective meanings given to such terms in the Credit Agreement.

1.2 Additional Defined Terms. As used herein, the following terms have the following respective meanings:

“Assigned Interest” shall mean, as to each of the Assignees, that percentage set forth below as to each of the Assignees of Assignor’s (in its capacity a Lender) rights and obligations (i) under the Credit Agreement and the other Loan Documents in respect of the Facility Amount of Assignor in the principal amount equal to $32,327,586.21, as of the Assignment Date, and (ii) to make Loans and participate in Letters of Credit under its Commitment and to receive payments for the Loans currently outstanding under its Commitments, plus the interest and fees which will accrue with respect thereto from and after the Assignment Date (resulting in the Dollar amount of such Facility Amount set forth below under the heading “Assigned Facility Amount” as to the relevant Assignee):

Assignee	Assigned Percentage of Assignor’s Facility Amount			Assigned Facility Amount
Compass		37.85714287040	%	$	12,238,300.50
Wells		25.42857141973	%	$	8,220,443.35
JPMC		6.23809524693	%	$	2,016,625.62
KeyBank		30.47619046293	%	$	9,852,216.74
		100.00000000000	%	$	32,327,586.21

“Assignment Date” shall mean December 23, 2013.

1.3 References. References in this Agreement to Schedule, Exhibit, Article, or Section numbers shall be to Schedules, Exhibits, Articles, or Sections of this Agreement, unless expressly stated to the contrary. References in this Agreement to “hereby,” “herein,” “hereinafter,” “hereinabove,” “hereinbelow,” “hereof,” “hereunder” and words of similar import shall be to this Agreement in its entirety and not only to the particular Schedule, Exhibit, Article, or Section in which such reference appears. Except as otherwise indicated, references in this Agreement to statutes, sections, or regulations are to be construed as including all statutory or regulatory provisions consolidating, amending, replacing, succeeding, or supplementing the statute, section, or regulation referred to. References in this Agreement to “writing” include printing, typing, lithography, facsimile reproduction, and other means of reproducing words in a tangible visible form. References in this Agreement to agreements and other contractual instruments shall be deemed to include all exhibits and appendices attached thereto and all subsequent amendments and other modifications to such instruments, but only to the extent such amendments and other modifications are not prohibited by the terms of this Agreement. References in this Agreement to Persons include their respective successors and permitted assigns.

1.4 Articles and Sections. This Agreement, for convenience only, has been divided into Articles and Sections; and it is understood that the rights and other legal relations of the parties hereto shall be determined from this instrument as an entirety and without regard to the aforesaid division into Articles and Sections and without regard to headings prefixed to such Articles or Sections.

1.5 Number and Gender. Whenever the context requires, reference herein made to the single number shall be understood to include the plural; and likewise, the plural shall be

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understood to include the singular. Definitions of terms defined in the singular or plural shall be equally applicable to the plural or singular, as the case may be, unless otherwise indicated. Words denoting sex shall be construed to include the masculine, feminine and neuter, when such construction is appropriate; and specific enumeration shall not exclude the general but shall be construed as cumulative.

1.6 Negotiated Transaction. Each party to this Agreement affirms to the other party hereto that it has had the opportunity to consult, and discuss the provisions of this Agreement with, independent counsel and fully understands the legal effect of each provision.

ARTICLE II

SALE AND ASSIGNMENT

2.1 Sale and Assignment. On the terms and conditions set forth herein, effective on and as of the Assignment Date, Assignor hereby sells, assigns and transfers to each of the Assignees, and each of the Assignees hereby purchases and assumes from Assignor, all of the right, title and interest of Assignor in and to, and all of the obligations of Assignor in respect of, the Assigned Interest of the relevant Assignee. Such sale, assignment and transfer is without recourse and, except as expressly provided in this Agreement, without representation or warranty.

2.2 Assumption of Obligations. Each of the Assignees agrees with Assignor (for the express benefit of Assignor and the Borrower) that such Assignee will, from and after the Assignment Date, assume and perform all of the obligations of Assignor in respect of the Assigned Interest of the relevant Assignee. From and after the Assignment Date: (a) Assignor shall be released from its obligations in respect of the Assigned Interests and (b) each of the Assignees shall be entitled to all of Assignor’s respective rights, powers and privileges under the Credit Agreement and the other Loan Documents in respect of the Assigned Interest of the relevant Assignee.

2.3 Consent by Agent. By executing this Agreement as provided below, in accordance with Section 9.1(b) of the Credit Agreement, the Agent hereby acknowledges notice of the transactions contemplated by this Agreement and consents to such transactions.

ARTICLE III

PAYMENTS

3.1 Payments. As consideration for the sale, assignment and transfer contemplated by Section 2.1, each of the Assignees shall, on the Assignment Date: (a) assume Assignor’s obligations in respect of the Assigned Interest of the relevant Assignee and (b) pay to Assignor an amount equal to the Loan Balance, if any, and all accrued and unpaid interest and fees with respect to the Assigned Interest of the relevant Assignee as of the Assignment Date. Except as otherwise provided in this Agreement, all payments hereunder shall be made in Dollars and in immediately available funds, without setoff, deduction or counterclaim.

3.2 Allocation of Payments. Assignor and the Assignees agree that: (a) Assignor shall be entitled to any payments of principal with respect to the Assigned Interests made prior to

- 3 -

the Assignment Date, together with any interest and fees with respect to the Assigned Interest accrued prior to the Assignment Date; (b) each of the Assignees shall be entitled to any payments of principal with respect to the Assigned Interest of the relevant Assignee made from and after the Assignment Date, together with any and all interest and fees with respect to the Assigned Interest of the relevant Assignee accruing from and after the Assignment Date; and (c) the Agent is authorized and instructed to allocate payments received by it for the account of Assignor and the Assignees as provided in the foregoing clauses. Each party hereto agrees that it will hold any interest, fees or other amounts that it may receive to which any other party hereto shall be entitled pursuant to the preceding sentence for the account of such other party and pay, in like money and funds, any such amounts that it may receive to such other party promptly upon receipt.

3.3 Delivery of Note. Promptly following the receipt by Assignor of the consideration required to be paid by an Assignee under Section 3.1 hereof, Assignor shall: (a) deliver to the Agent (or its counsel) the Note held by Assignor and (ii) notify the Agent to request that the Borrower execute and deliver a new Note to such Assignee, dated as of the Assignment Date.

3.4 Further Assurances. Assignor and the Assignees hereby agree to execute and deliver such other instruments, and take such other actions, as any party hereto may reasonably request in connection with the transactions contemplated by this Agreement.

ARTICLE IV

CONDITIONS PRECEDENT

The effectiveness of the sale, assignment and transfer contemplated hereby is subject to the satisfaction of each of the following conditions precedent:

(a) the execution and delivery of this Agreement by Assignor and the Assignees;

(b) the receipt by Assignor of the payments required to be made under Section 3.1; and

(c) the acknowledgment and consent by the Agent as contemplated by Section 2.3.

ARTICLE V

REPRESENTATIONS AND WARRANTIES

5.1 Representations and Warranties of Assignor. Assignor represents and warrants to the Assignees as follows:

(a) Assignor has all requisite power and authority, and has taken all action necessary to execute and deliver this Agreement and to fulfill its obligations under, and consummate the transactions contemplated by, this Agreement;

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(b) the execution, delivery and compliance with the terms hereof by Assignor and the delivery of all instruments required to be delivered by it hereunder do not and will not violate any Requirement of Law applicable to it;

(c) this Agreement has been duly executed and delivered by it and constitutes the legal, valid and binding obligation of Assignor, enforceable against it in accordance with its terms;

(d) all approvals and authorizations of, all filings with and all actions by any Governmental Authority necessary for the validity or enforceability of its obligations under this Agreement have been obtained;

(e) Assignor has good title to, and is the sole legal and beneficial owner of, the Assigned Interest, free and clear of all Liens, claims, participations or other charges of any nature whatsoever; and

(f) the transactions contemplated by this Agreement are commercial banking transactions entered into in the ordinary course of the banking business of Assignor.

5.2 Disclaimer. Except as expressly provided in Section 5.1 hereof, Assignor does not make any representation or warranty, nor shall Assignor have any responsibility to any Assignee, with respect to the accuracy of any recitals, statements, representations or warranties contained in the Credit Agreement or in any other Loan Document or for the value, validity, effectiveness, genuineness, execution, legality, enforceability or sufficiency of the Credit Agreement, the Notes or any other Loan Document or for any failure by the Borrower or any other Person (other than Assignor) to perform any of its obligations thereunder or for the existence, value, perfection or priority of any collateral security or the financial or other condition of the Borrower or any other Person, or any other matter relating to the Credit Agreement or any other Loan Document or any extension of credit thereunder.

5.3 Representations and Warranties of Assignees. Each of the Assignees represents and warrants to Assignor as follows:

(a) such Assignee has all requisite power and authority, and has taken all action necessary to execute and deliver this Agreement and to fulfill its obligations under, and consummate the transactions contemplated by, this Agreement;

(b) the execution, delivery and compliance with the terms hereof by such Assignee and the delivery of all instruments required to be delivered by it hereunder do not and will not violate any Requirement of Law applicable to it;

(c) this Agreement has been duly executed and delivered by it and constitutes the legal, valid and binding obligation of such Assignee, enforceable against it in accordance with its terms;

- 5 -

(d) all approvals and authorizations of, all filings with and all actions by any Governmental Authority necessary for the validity or enforceability of its obligations under this Agreement have been obtained;

(e) such Assignee has received copies of the Credit Agreement and the other Loan Documents, as well as copies of all Financial Statements previously provided by the Borrower in satisfaction of obligations under the Credit Agreement;

(f) such Assignee has fully reviewed the terms of the Credit Agreement and the other Loan Documents and has independently and without reliance upon Assignor, and based on such information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement;

(g) if such Assignee is not incorporated under the laws of the United States of America or a state thereof, such Assignee has contemporaneously herewith delivered to the Agent and the Borrower such documents as are required by the Credit Agreement; and

(h) the transactions contemplated by this Agreement are commercial banking transactions entered into in the ordinary course of the banking business of such Assignee.

ARTICLE VI

MISCELLANEOUS

6.1 Notices. All notices and other communications provided for herein (including any modifications of, or waivers, requests or consents under, this Agreement) shall be given or made in writing (including by telecopy) to the intended recipient at its “Address for Notices” specified below its name on the signature pages hereof or, as to any party hereto, at such other address as shall be designated by such party in a notice to the other parties hereto.

6.2 Amendment, Modification or Waiver. No provision of this Agreement may be amended, modified or waived except by an instrument in writing signed by Assignor and the Assignees, and consented to by the Agent.

6.3 Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns. The representations and warranties made herein by each of the Assignees are also made for the benefit of the Agent, and each of the Assignees agrees that the Agent is entitled to rely upon such representations and warranties.

6.4 Assignments. No party hereto may assign any of its rights or obligations hereunder except in accordance with the terms of the Credit Agreement.

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6.5 Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be identical and all of which, taken together, shall constitute one and the same instrument and shall be effective against the parties hereto only upon execution of one or more counterparts hereof by all parties hereto.

6.6 Governing Law. THIS AGREEMENT (INCLUDING THE VALIDITY AND ENFORCEABILITY HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS, OTHER THAN THE CONFLICT OF LAWS RULES THEREOF.

6.7 Expenses. To the extent not paid by the Borrower pursuant to the terms of the Credit Agreement, each party hereto shall bear its own expenses in connection with the execution, delivery and performance of this Agreement.

6.8 Waiver of Jury Trial. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

[Signatures appear on following pages]

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IN WITNESS WHEREOF, the parties hereto have caused this Assignment Agreement to be executed and delivered as of the date first above written.

ASSIGNOR:
AMEGY BANK NATIONAL ASSOCIATION
By:	/s/ Mark A. Serice
	Mark A. Serice
	Senior Vice President
Address for Notices:
4400 Post Oak Parkway 4th Floor Houston, Texas 77027 Attention: Energy Lending Dept. Facsimile No. (713) 561-0345 Telephone No.: (713) 232-1110

(Signature page to Assignment Agreement)

ASSIGNEE:
COMPASS BANK (successor in interest to Guaranty Bank, FSB)
By:	/s/ Kathleen J. Bowen
	Kathleen J. Bowen
	Senior Vice President
Address for Notices:
2200 Post Oak Blvd., 21st Floor
Houston, Texas 77056 Attention: Kathleen J. Bowen

(Signature page to Assignment Agreement)

ASSIGNEE:
WELLS FARGO BANK, NATIONAL ASSOCIATION
By:	/s/ Betsy Jocher
Name:	Betsy Jocher
Title:	Director
Address for Notices:
1000 Louisiana Street, 9th Floor
Houston, TX 77002
Attn:	Betsy Jocher

Facsimile No.: 713-319-1925

(Signature page to Assignment Agreement)

ASSIGNEE:
JPMORGAN CHASE BANK, N.A.
By:	/s/ Alexander Wilk
Name:	Alexander Wilk
Title:	Authorized Signatory
Address for Notices:
Attn:

Facsimile No.:

(Signature page to Assignment Agreement)

ASSIGNEE:
KEYBANK NATIONAL ASSOCIATION
By:	/s/ Sherrie I. Manson
Name:	Sherrie I. Manson
Title:	Senior Vice President
Address for Notices:
4900 Tiedeman Road
Brooklyn, Oh 44144-2302
Attn:	Yvette Dyson-Owens

Facsimile No.: 216-370-6119

(Signature page to Assignment Agreement)

ACKNOWLEDGED AND CONSENTED TO:
COMPASS BANK (successor in interest to Guaranty Bank, FSB), as Agent
By:	/s/ Kathleen J. Bowen
	Kathleen J. Bowen
	Senior Vice President
PRIMEENERGY CORPORATION
By:	/s/ Beverly A. Cummings
	Beverly A. Cummings
	Executive Vice President, Treasurer
	and Chief Financial Officer

(Signature page to Assignment Agreement)

EX-21

Exhibit 21

SUBSIDIARIES

PrimeEnergy Management Corporation, a New York corporation, 100% owned by PrimeEnergy Corporation.

Prime Operating Company, a Texas corporation, 100% owned by PrimeEnergy Corporation.

Eastern Oil Well Service Company, a West Virginia corporation, 100% owned by PrimeEnergy Corporation.

Southwest Oilfield Construction Company, an Oklahoma corporation, 100% owned by PrimeEnergy Corporation.

E O W S Midland Company, a Texas corporation, 100% owned by PrimeEnergy Corporation.

Prime Offshore L.L.C., a Delaware limited liability company, 90% owned by PrimeEnergy Corporation.

Chase Energy L.L.C., a Texas limited liability company, 50% owned by PrimeEnergy Corporation.

EX-23

Exhibit 23

		FAX (303) 623-4258
621 SEVENTEENTH STREET	SUITE 1550	DENVER, COLORADO 80293
TELEPHONE (303) 623-9147

CONSENT OF RYDER SCOTT COMPANY, L.P.

We consent to the filing of our summary reserve report dated March 7, 2014, as Exhibit 99.1 to the PrimeEnergy Corporation annual report on Form 10-K for the year ended December 31, 2013 and to any reference made to us on that form 10-K.

Very Truly Yours,

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

Denver, Colorado

March 25, 2014

1100 LOUISIANA, SUITE 3800HOUSTON, TEXAS 77002-5218          TEL (713) 651-9191          FAX (713) 651-0849

530 8TH AVENUE, S.W., SUITE 1200CALGARY, ALBERTA T2P 3S8TEL (403) 262-2799         FAX (403) 262-2790

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Charles E. Drimal, Jr., Chief Executive Officer of PrimeEnergy Corporation, certify that:

1. I have reviewed this Annual report on Form 10-K for the year ended December 31, 2013 of PrimeEnergy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 25, 2014	/s/ Charles E. Drimal, Jr.
	Charles E. Drimal, Jr.
	Chief Executive Officer
	PrimeEnergy Corporation

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Corporation, certify that:

1. I have reviewed this Annual report on Form 10-K for the year ended December 31, 2013 of PrimeEnergy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 25, 2014	/s/ Beverly A. Cummings
	Beverly A. Cummings
	Chief Financial Officer
	PrimeEnergy Corporation

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of PrimeEnergy Corporation (the “Company”) on Form 10-K for the period ending December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Charles E. Drimal Jr., Chief Executive Officer of PrimeEnergy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Charles E. Drimal, Jr.

Charles E. Drimal, Jr.

Chief Executive Officer

March 25, 2014

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of PrimeEnergy Corporation (the “Company”) on Form 10-K for the period ending December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Beverly A. Cummings, Chief Financial Officer of PrimeEnergy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Beverly A. Cummings

Beverly A. Cummings

Chief Financial Officer

March 25, 2014

EX-99.1

Exhibit 99.1

FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE (303) 623-9147

March 7, 2014

PrimeEnergy Corporation

One Landmark Square

Stamford, Connecticut 06901

Dear Ms. Beverly A. Cummings,

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of PrimeEnergy Corporation and 100 percent of its’ Partnership Interests (PrimeEnergy) as of December 31, 2013. The subject properties are located in the states of Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas, West Virginia and Wyoming. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on March 7, 2014 and presented herein, was prepared for public disclosure by PrimeEnergy in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of PrimeEnergy as of December 31, 2013.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2013 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

PrimeEnergy Corporation and 100% of Partnership Interests

As of December 31, 2013

	Proved
	Developed				Undeveloped		Other Deductions			Total Proved
	Producing		Non-Producing
Net Remaining Reserves
Oil/Condensate – Barrels		6,376,292		310,676		9,066,316		0			15,753,284
Plant Products - Barrels		2,175,108		48,440		3,706,551		0			5,930,099
Gas – MCF		29,599,998		2,027,584		19,772,082		0			51,399,664
Income Data
Future Gross Revenue	$	753,171,632	$	38,613,272	$	987,199,443	$	0		$	1,778,984,347
Deductions		430,897,353		11,985,422		531,577,640		7,061,041			981,521,456
Future Net Income (FNI)	$	322,274,279	$	26,627,850	$	455,621,803	$	(7,061,041	)	$	797,462,891
Discounted FNI @ 10%	$	193,481,717	$	15,308,287	$	131,509,830	$	(4,464,277	)	$	335,835,557

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in thousands of cubic feet (MCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation Software, a copyrighted program of TRC Consultants L.C. The program was used at the request of PrimeEnergy. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs and certain abandonment costs net of salvage. “Other Deductions” incorporate contractual net cash flow adjustments as provided by PrimeEnergy. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 89 percent and gas reserves account for the remaining 11 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded yearly. Future net income was discounted at four other discount rates which were also compounded yearly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

	Discounted Future Net Income As of December 31, 2013
Discount Rate Percent	Total Proved
5	$	491,456,212
15	$	245,147,772
20	$	187,181,381
25	$	147,667,059

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PrimeEnergy’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PrimeEnergy’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PrimeEnergy owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Essentially all of the proved

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis and material balance which utilized extrapolations of historical production and pressure data available through December 2013 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by PrimeEnergy or obtained from public data sources and were considered sufficient for the purpose thereof.

Approximately 95 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by analogy. The data utilized in this analysis were considered sufficient for the purpose thereof. Approximately 5 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by PrimeEnergy or which we have obtained from public data sources that were available through December 2013. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PrimeEnergy has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PrimeEnergy with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by PrimeEnergy. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PrimeEnergy. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

PrimeEnergy furnished us with the above mentioned average prices in effect on December 31, 2013. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PrimeEnergy.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$96.78/Bbl	$91.32/Bbl
	NGL’s	WTI Cushing	$96.78/Bbl	$41.08/Bbl
	Gas	Henry Hub	$3.67/MMBTU	$3.85/MCF

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by PrimeEnergy and are based on the operating expense reports of PrimeEnergy and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PrimeEnergy. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PrimeEnergy and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by PrimeEnergy were accepted without independent verification.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with PrimeEnergy’s plans to develop these reserves as of December 31, 2013. The implementation of PrimeEnergy’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PrimeEnergy’s management. As the result of our inquiries during the course of preparing this report, PrimeEnergy has informed us that the development activities included herein have been subjected to and received the internal approvals required by PrimeEnergy’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PrimeEnergy. Additionally, PrimeEnergy has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by PrimeEnergy were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to PrimeEnergy. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PrimeEnergy.

We have provided PrimeEnergy with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by PrimeEnergy and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPE Firm Registration No. F-1580
[Seal]	/s/ James L. Baird
	James L. Baird, P.E.
	Colorado License No. 41521
	Managing Senior Vice President
	/s/ Richard J. Marshall                [Seal]
	Richard J. Marshall, P.E.
	Colorado License No. 23260
	Vice President

JLB-RJM /pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Richard J. Marshall was the primary technical person responsible for overseeing the estimate of the future net reserves and income.

Mr. Marshall, an employee of Ryder Scott Company L.P. (Ryder Scott) beginning in 1981, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies. Before joining Ryder Scott, Mr. Marshall served in a number of engineering positions with Texaco, Phillips Petroleum, and others. For more information regarding Mr. Marshall’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Marshall earned a B.S. in Geology from the University of Missouri in 1974 and a M.S. in Geological Engineering from the University of Missouri at Rolla in 1976. Mr. Marshall is a registered Professional Engineer in the State of Colorado. He is a member of the Society of Petroleum Engineers, Wyoming Geological Association, Rocky Mountain Association of Geologists and the Society of Petroleum Evaluation Engineers.

Based on Mr. Marshall’s educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Marshall has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

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Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Minimum [Member]	Dec. 31, 2013 Maximum [Member]	Dec. 31, 2013 Equipment Loan [Member]	Jul. 31, 2013 Equipment Loan [Member]	Dec. 31, 2013 Interest Rate Swap [Member]
Debt Instrument [Line Items]
Credit facility borrowing capacity	$ 250,000,000
Maturity date of amended and restated credit agreement	Jul. 30, 2017
Maximum percentage of production	90.00%
Restrictions on the payment of dividends, distributions or purchase of treasury stock	5,000,000
Credit facility borrowing base	140,000,000
Credit facility, interest rate description	The Company's borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at December 31, 2013) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.50% to 3.00%. At December 31, 2013, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.92%, respectively.
Percentage for base rate loans at the prime rate	3.25%				3.95%		0.563%
Minimum range for applicable margin utilization rate	1.50%
Maximum range for applicable margin utilization rate	2.00%
Debt instrument interest one base rate basis for effective rate	5.00%
LIBOR rate loans			2.50%	3.00%
Effective LIBOR loan rate	2.92%
Outstanding borrowings under revolving credit facility	112,500,000
Weighted-average interest rate of borrowings	3.06%
Credit facility remaining borrowing capacity	27,500,000
Debt instrument basis weighted average interest rate spread on variable rate	3.58%	3.81%
Interest swap agreements period	2 years
Company's bank debt					9,400,000		75,000,000
Equipment Loan, face amount						10,000,000
Equipment Loan, monthly payment					$ 184,000
Equipment Loan, maturity date					Jul. 31, 2018

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Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Gain on settlement of derivative instruments	$ 1.03
Net proceeds from derivative instruments	$ 1.03

XML

Segment Information and Major Customers - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 Industry
Revenue, Major Customer [Line Items]
Number of industry in which company operates	1
Minimum [Member] | Sales [Member]
Revenue, Major Customer [Line Items]
Customer purchases with respect of company's sales	10.00%

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Related Party Transactions - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Board of Directors [Member]	Apr. 30, 2012 Board of Directors [Member]	Dec. 31, 2013 Other Related Party [Member]	Dec. 31, 2012 Other Related Party [Member]
Related Party Transaction [Line Items]
Repurchase interests of partners and trust unit holders	$ 48,000	$ 149,000
Treasury stock, shares	1,447,613	1,325,837	4,500	45,179	0	0
Treasury stock	$ 40,251,000	$ 36,113,000	$ 222,750	$ 1,130,000

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Income Taxes - Provision for Income Taxes Varies from Federal Statutory Tax Rate (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Expected tax expense	$ 6,491	$ 7,450
State income tax, net of federal benefit	488	(112)
Percentage depletion	(422)	(902)
Other, net	261	420
Total income tax provision	$ 6,818	$ 6,856

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Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings (Loss) Per Share

The following reconciles amounts reported in the financial statements:

	Year Ended December 31,
	2013						2012
	Net Income (In  000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In  000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	12,271		2,436,821	$	5.04	$	15,056		2,624,335	$	5.74
Effect of dilutive securities:
Options		—		746,085				—		735,244
Diluted	$	12,271		3,182,906	$	3.86	$	15,056		3,359,579	$	4.48

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Salary Deferral Plan - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Compensation And Retirement Disclosure [Abstract]
Salary deferral plan, discretionary and matching contribution	$ 525,000	$ 463,000

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Shareholder's Equity

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Shareholder's Equity

16. Shareholder’s Equity

The Company has in place a stock repurchase program whereby it may purchase outstanding shares of its common stock from time-to-time, in open market transactions or negotiated sales. The Company uses the cost method to account for its treasury share purchases.

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Financial Instruments - Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Assets
Derivative assets	$ 1,423	$ 1,347
Liabilities
Derivative liabilities	(2,288)	(1,425)
Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	1,423	1,347
Liabilities
Derivative liabilities	(2,288)	(1,425)
Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	1,337	1,347
Liabilities
Derivative liabilities	(2,010)	(1,371)
Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	86
Liabilities
Derivative liabilities	(278)	(54)
Quoted Prices in Active Markets For Identical Assets (Level 1) [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets
Liabilities
Derivative liabilities
Quoted Prices in Active Markets For Identical Assets (Level 1) [Member] | Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets
Liabilities
Derivative liabilities
Quoted Prices in Active Markets For Identical Assets (Level 1) [Member] | Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets
Liabilities
Derivative liabilities
Significant Other Observable Inputs (Level 2) [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets
Liabilities
Derivative liabilities
Significant Other Observable Inputs (Level 2) [Member] | Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets
Liabilities
Derivative liabilities
Significant Other Observable Inputs (Level 2) [Member] | Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets
Liabilities
Derivative liabilities
Significant Unobservable Inputs (Level 3) [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	1,423	1,347
Liabilities
Derivative liabilities	(2,288)	(1,425)
Significant Unobservable Inputs (Level 3) [Member] | Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	1,337	1,347
Liabilities
Derivative liabilities	(2,010)	(1,371)
Significant Unobservable Inputs (Level 3) [Member] | Interest Rate Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Assets
Derivative assets	86
Liabilities
Derivative liabilities	$ (278)	$ (54)

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Commitments - Reconciliation of Liability for Plugging and Abandonment Costs (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]
Asset retirement obligation at beginning of period	$ 9,012	$ 19,013
Liabilities incurred	338	733
Loss on settlement of obligations	40
Liabilities settled	(776)	(15,361)
Accretion expense	394	1,053
Revisions in estimated liabilities	1,529	3,574
Asset retirement obligation at end of period	$ 10,537	$ 9,012

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Additional Balance Sheet Information - Components of Balance Sheet Amounts (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Accounts Receivable:
Joint interest billings	$ 6,287	$ 2,189
Trade receivables	2,014	1,580
Oil and gas sales	9,604	9,362
Other	122	436
Accounts Receivable, Gross	18,027	13,567
Less: Allowance for doubtful accounts	(334)	(355)
Total	17,693	13,212
Accounts Payable:
Trade	1,596	3,968
Royalty and other owners	7,391	9,652
Partner advances	3,378	3,589
Prepaid drilling deposits	978	306
Other	2,906	2,053
Total	16,249	19,568
Accrued Liabilities:
Compensation and related expenses	3,062	2,517
Property costs	3,119	4,549
Income tax	268
Other	383	552
Total	$ 6,832	$ 7,618

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Financial Instruments - Effect of Derivative Instruments on Consolidated Balance Sheets (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative assets	$ 1,423	$ 1,347
Derivative liabilities	(2,288)	(1,425)
Total derivative instruments	(865)	(78)
Other Assets [Member] | Interest Rate Swap [Member] | Derivatives Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	86
Other Assets [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	980	118
Derivative Contracts [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	307	189
Derivative Contracts [Member] | Natural Gas Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative assets	50	1,040
Derivative Liability Short-Term [Member] | Interest Rate Swap [Member] | Derivatives Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(209)
Derivative Liability Short-Term [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(1,667)	(994)
Derivative Liability Short-Term [Member] | Natural Gas Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(318)
Derivative Liability Long-Term [Member] | Interest Rate Swap [Member] | Derivatives Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	(69)	(54)
Derivative Liability Long-Term [Member] | Crude Oil Commodity Contracts [Member] | Derivatives Not Designated as Cash-Flow Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ (25)	$ (377)

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Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Future cash inflows	$ 1,880,389	$ 1,524,137
Future production costs	(769,172)	(673,629)
Future development costs	(313,754)	(179,568)
Future income tax expenses	(234,191)	(186,072)
Future Net Cash Flows	563,272	484,868
10% annual discount for estimated timing of cash flows	(325,044)	(271,595)
Standardized Measure of Discounted Future Net Cash Flows	$ 238,228	$ 213,273

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal income tax return, total refunds	$ 685,000
Alternative minimum tax credits	5,852,000	5,890,000
Provision for uncertain tax positions	$ 0

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Consolidated Statement of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities:
Net income	$ 13,440	$ 14,774
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities	21,861	23,269
Gain on sale of properties	(2,816)	(730)
Unrealized (gain) loss on derivative instruments	649	(3,483)
Provision for deferred income taxes	7,014	6,970
Loss on settlement of asset retirement obligations	40
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(4,481)	3,294
Increase in due from related parties	(96)	(25)
(Increase) decrease in inventories	91	(2)
Decrease in prepaid expenses and other assets	378	5,761
Decrease in accounts payable	(712)	(9,500)
Increase (decrease) in accrued liabilities	332	(616)
Net Cash Provided by Operating Activities	35,700	39,712
Cash Flows from Investing Activities:
Capital expenditures, including exploration expense	(33,934)	(86,305)
Proceeds from sale of properties and equipment	3,681	881
Net Cash Used in Investing Activities	(30,253)	(85,424)
Cash Flows from Financing Activities:
Purchase of stock for treasury	(4,138)	(4,993)
Purchase of non-controlling interests	(48)	(149)
Increase in long-term bank debt and other long-term obligations	68,750	111,800
Repayment of long-term bank debt and other long-term obligations	(68,857)	(59,857)
Distribution to non-controlling interest	(230)	(1,148)
Net Cash (Used in) Provided by Financing Activities	(4,523)	45,653
Net Increase (Decrease) in Cash and Cash Equivalents	924	(59)
Cash and Cash Equivalents at the Beginning of the Year	8,602	8,661
Cash and Cash Equivalents at the End of the Year	9,526	8,602
Supplemental Disclosures:
Income taxes paid during the year	754	536
Interest paid during the year	$ 4,183	$ 3,535

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Supplementary Information - Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Sales of oil and gas produced, net of production costs	$ (48,976)	$ (48,673)
Net changes in prices and production costs	(10,149)	504
Extensions, discoveries and improved recovery	218,648	164,557
Revisions of previous quantity estimates	(733)	40,964
Net change in development costs	(129,672)	(145,382)
Reserves sold
Reserves purchased		6,563
Accretion of discount	21,327	18,451
Net change in income taxes	(23,007)	(5,952)
Changes in production rates (timing) and other	(2,483)	(2,267)
Net change	24,955	28,765
Standardized measure of discounted future net cash flow:
Beginning of year	213,273	184,508
End of year	$ 238,228	$ 213,273

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Stock Options and Other Compensation - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	May 31, 1989 Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options outstanding, shares	767,500	767,500
Option exercisable, shares	767,500	767,500
Number of key executive officers to whom non-statutory stock options granted			4
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average exercise price	$ 1.00	$ 1.00
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average exercise price	$ 1.25	$ 1.25

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Commitments (Tables)

12 Months Ended

Dec. 31, 2013

Commitments And Contingencies Disclosure [Abstract]

Summary of Future Minimum Lease Payments for Non-Cancelable Operating Leases

 The future minimum lease payments for the operating leases at December 31, 2013 are as follows.

(Thousands of dollars)	Operating Leases
2014	$	747
2015		651
2016		545
2017		46
Total minimum payments	$	1,989

Reconciliation of Liability for Plugging and Abandonment Costs

A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2013 and 2012 is as follows:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Asset retirement obligation at beginning of period	$	9,012		$	19,013
Liabilities incurred		338			733
Loss on settlement of obligations		40			—
Liabilities settled		(776	)		(15,361	)
Accretion expense		394			1,053
Revisions in estimated liabilities		1,529			3,574
Asset retirement obligation at end of period	$	10,537		$	9,012

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Additional Balance Sheet Information (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Components of Balance Sheet Amounts

Accounts receivable at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013			2012
Joint interest billings	$	6,287		$	2,189
Trade receivables		2,014			1,580
Oil and gas sales		9,604			9,362
Other		122			436
		18,027			13,567
Less: Allowance for doubtful accounts		(334	)		(355	)
Total	$	17,693		$	13,212

Accounts payable at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013		2012
Trade	$	1,596	$	3,968
Royalty and other owners		7,391		9,652
Partner advances		3,378		3,589
Prepaid drilling deposits		978		306
Other		2,906		2,053
Total	$	16,249	$	19,568

Accrued liabilities at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013		2012
Compensation and related expenses	$	3,062	$	2,517
Property costs		3,119		4,549
Income tax		268		—
Other		383		552
Total	$	6,832	$	7,618

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Restricted Cash and Cash Equivalents - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Cash And Cash Equivalents [Abstract]
Restricted cash and cash equivalents pertaining to oil and gas revenue payments	$ 2.01	$ 4.44

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Income Taxes - Components of Provision (Benefit) for Income Taxes (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Current:
Federal	$ (462)	$ 16
State	266	(130)
Total current	(196)	(114)
Deferred:
Federal	6,549	7,009
State	465	(39)
Total deferred	7,014	6,970
Total income tax provision	$ 6,818	$ 6,856

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Components of Provision (Benefit) for Income Taxes

The components of the provision (benefit) for income taxes for the years ended December 31, 2013 and 2012 are as follows:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Current:
Federal	$	(462	)	$	16
State		266			(130	)
Total current		(196	)		(114	)
Deferred:
Federal		6,549			7,009
State		465			(39	)
Total deferred		7,014			6,970
Total income tax provision	$	6,818		$	6,856

Components of Net Deferred Tax Assets and Liabilities

The components of net deferred tax assets and liabilities are as follows:

	At December 31,
(Thousands of dollars)	2013		2012
Current Assets:
Accrued liabilities	$	683	$	613
Allowance for doubtful accounts		118		124
Derivative contracts		677		(83	)
Total current deferred income tax assets	$	1,478	$	654
Non-Current Assets:
Alternative minimum tax credits	$	5,852	$	5,890
Net operating loss carry-forwards		168		114
Percentage depletion carry-forwards		4,543		4,287
Derivative contracts		—		91
Total non-current assets		10,563		10,382
Non-Current Liabilities:
Basis differences relating to managed partnerships		2,462		1,492
Depletion and depreciation		39,694		33,084
Derivative contracts		369		—
Total non-current liabilities		42,525		34,576
Net non-current deferred income tax liabilities	$	31,962	$	24,194

Provision for Income Taxes Varies from Federal Statutory Tax Rate

The total provision for income taxes for the years ended December 31, 2013 and 2012 varies from the federal statutory tax rate as a result of the following:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Expected tax expense	$	6,491		$	7,450
State income tax, net of federal benefit		488			(112	)
Percentage depletion		(422	)		(902	)
Other, net		261			420
Total income tax provision	$	6,818		$	6,856

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Segment Information and Major Customers (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Information by Major Customers

The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company’s total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company’s oil and gas sales in the year 2013.

Oil Purchasers:			Gas Purchasers:
Plains All American Inc.	52	%	Atlas Pipeline Mid-Continent	40	%
Sunoco, Inc.	28	%	Unimark LLC	13	%

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Consolidated Statement of Equity (Parenthetical)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Purchase of common stock, shares	121,776	191,309
Treasury Stock [Member]
Purchase of common stock, shares	121,776	191,309
Total Stockholders' Equity - PrimeEnergy [Member]
Purchase of common stock, shares	121,776	191,309

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis

The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2013 and 2012:

December 31, 2013 (Thousands of dollars)	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2013
Assets
Commodity derivative contracts	$	—	$	—	$	1,337		$	1,337
Interest rate derivative contracts		—		—		86			86
Total assets	$	—	$	—	$	1,423		$	1,423
Liabilities
Commodity derivative contracts	$	—	$	—	$	(2,010	)	$	(2,010	)
Interest rate derivative contracts		—		—		(278	)		(278	)
Total liabilities	$	—	$	—	$	(2,288	)	$	(2,288	)

December 31, 2012 (Thousands of dollars)	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2012
Assets
Commodity derivative contracts	$	—	$	—	$	1,347		$	1,347
Total assets	$	—	$	—	$	1,347		$	1,347
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,371	)	$	(1,371	)
Interest rate derivative contracts		—		—		(54	)		(54	)
Total liabilities	$	—	$	—	$	(1,425	)	$	(1,425	)

Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012.

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Net liabilities at beginning of period	$	(78	)	$	(3,507	)
Total realized and unrealized (gains) losses:
Included in earnings(a)		(1,971	)		3,985
Included in other comprehensive loss		(138	)		(54	)
Purchases, sales, issuances and settlements		1,322			(502	)
Net liabilities at end of period	$	(865	)	$	(78	)

^(a)  Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as a reduction to interest expense.

Effect of Derivative Instruments on Consolidated Balance Sheets

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2013 and 2012:

		Fair Value at December 31,
(Thousands of dollars)	Balance Sheet Location	2013			2012
Asset Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Other assets	$	86		$	—
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative contracts		307			189
Natural gas commodity contracts	Derivative contracts		50			1,040
Crude oil commodity contracts	Other assets		980			118
Total		$	1,423		$	1,347
Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Derivative liability short-term	$	(209	)	$	—
Interest rate swap contracts	Derivative liability long-term		(69	)		(54	)
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term		(1,667	)		(994	)
Natural gas commodity contracts	Derivative liability short-term		(318	)		—
Crude oil commodity contracts	Derivative liability long-term		(25	)		(377	)
Total		$	(2,288	)	$	(1,425	)
Total derivative instruments		$	(865	)	$	(78	)

Effect of Derivative Instruments on Consolidated Statements of Operations

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2013 and 2012:

(Thousands of dollars)	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
		2013			2012
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net	$	(1,309	)	$	1,040
Crude oil commodity contracts	Unrealized gain on derivative instruments, net		660			2,443
Natural gas commodity contracts(a)	Realized gain on derivative instruments, net		796			—
Crude oil commodity contracts(a)	Realized gain (loss) on derivative instruments, net		(2,118	)		502
		$	(1,971	)	$	3,985

^(a)  In January 2012, March 2012 and May 2012, the Company unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for aggregated net proceeds of $1.03 million. The $1.03 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.

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Commitments - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]
Lease period description	Term of more than one year
Rent expense for office space	$ 699,000	$ 755,000

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Financial Instruments - Effect of Derivative Instruments on Consolidated Statements of Operations (Detail) (Derivatives Not Designated as Cash-Flow Hedging Instruments [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Derivatives not designated as cash-flow hedge instruments:
Amount of gain/loss recognized in income	$ (1,971)	$ 3,985
Unrealized Gain (Loss) on Derivative Instruments, Net [Member] | Natural Gas Commodity Contracts [Member]
Derivatives not designated as cash-flow hedge instruments:
Amount of gain/loss recognized in income	(1,309)	1,040
Unrealized Gain (Loss) on Derivative Instruments, Net [Member] | Crude Oil Commodity Contracts [Member]
Derivatives not designated as cash-flow hedge instruments:
Amount of gain/loss recognized in income	660	2,443
Realized Gain (Loss) on Derivative Instruments, Net [Member] | Natural Gas Commodity Contracts [Member]
Derivatives not designated as cash-flow hedge instruments:
Amount of gain/loss recognized in income	796
Realized Gain (Loss) on Derivative Instruments, Net [Member] | Crude Oil Commodity Contracts [Member]
Derivatives not designated as cash-flow hedge instruments:
Amount of gain/loss recognized in income	$ (2,118)	$ 502

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Consolidated Balance Sheet (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 9,526	$ 8,602
Restricted cash and cash equivalents	2,065	4,672
Accounts receivable, net	17,693	13,212
Prepaid obligations	1,188	1,656
Derivative contracts	357	1,229
Other current assets	1,846	1,081
Total Current Assets	32,675	30,452
Property and Equipment
Oil and gas properties at cost	364,123	338,204
Less: Accumulated depletion and depreciation	(169,100)	(150,276)
Oil and gas properties, Net	195,023	187,928
Field and office equipment at cost	26,653	23,974
Less: Accumulated depreciation	(13,251)	(15,052)
Field and office equipment, Net	13,402	8,922
Total Property and Equipment, Net	208,425	196,850
Derivative Contracts Long-Term	1,066	118
Other Assets	756	666
Total Assets	242,922	228,086
Current Liabilities
Accounts payable	16,249	19,568
Accrued liabilities	6,832	7,618
Current portion of long-term debt	1,870
Current portion of asset retirement and other long-term obligations	3,310	2,148
Derivative liability short-term	2,194	994
Due to related parties	23	67
Total Current Liabilities	30,478	30,395
Long-Term Bank Debt	120,023	122,000
Asset Retirement Obligations	7,227	6,864
Derivative Liability Long-Term	94	431
Deferred Income Taxes	31,962	24,194
Total Liabilities	189,784	183,884
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2013 and 2012: Authorized: 4,000,000 shares, issued: 3,836,397 shares; outstanding 2013: 2,388,784 shares; 2012: 2,510,560 shares	383	383
Paid-in capital	6,803	6,690
Retained earnings	78,616	66,345
Accumulated other comprehensive loss, net	(123)	(35)
Treasury stock, at cost; 2013: 1,447,613 shares; 2012: 1,325,837 shares	(40,251)	(36,113)
Total Stockholders' Equity-PrimeEnergy	45,428	37,270
Non-controlling interest	7,710	6,932
Total Equity	53,138	44,202
Total Liabilities and Equity	$ 242,922	$ 228,086

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Income Taxes - Components of Net Deferred Tax Assets and Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current Assets:
Accrued liabilities	$ 683	$ 613
Allowance for doubtful accounts	118	124
Derivative contracts	677	(83)
Total current deferred income tax assets	1,478	654
Non-Current Assets:
Alternative minimum tax credits	5,852	5,890
Net operating loss carry-forwards	168	114
Percentage depletion carry-forwards	4,543	4,287
Derivative contracts		91
Total non-current assets	10,563	10,382
Non-Current Liabilities:
Basis differences relating to managed partnerships	2,462	1,492
Depletion and depreciation	39,694	33,084
Derivative contracts	369
Total non-current liabilities	42,525	34,576
Net non-current deferred income tax liabilities	$ 31,962	$ 24,194

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Consolidated Statement of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Changes in fair value of hedge positions, tax	$ 50	$ 19

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Supplementary Information - Capitalized Costs Relating to Oil and Gas Producing Activities (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Proved Developed oil and gas properties	$ 362,186	$ 336,135
Proved Undeveloped oil and gas properties	1,937	2,069
Unproved oil and gas properties
Total Capitalized Costs	364,123	338,204
Accumulated depreciation, depletion and valuation allowance	169,100	150,276
Net Capitalized Costs	$ 195,023	$ 187,928

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Description of Operations and Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 Trust Well Partnership
Property, Plant and Equipment [Line Items]
Number of wells operating by the company	1,600
Minimum number of wells under non-operating interests	800
Number of limited partnerships	18
Number of business income trusts	2
Maximum maturity period of cash and cash equivalents	90 days
Maximum [Member]
Property, Plant and Equipment [Line Items]
Depreciation period of equipment	10 years
Minimum [Member]
Property, Plant and Equipment [Line Items]
Depreciation period of equipment	5 years

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Supplementary Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Interest rate of Company's reserves	10.00%
Rate of discounted future net cash flows	10.00%
Percentage of discounted future prices	10.00%

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Restricted Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2013

Cash And Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents

13. Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents include $2.01 million and $4.44 million at December 31, 2013 and 2012, respectively, of cash primarily pertaining to oil and gas revenue payments. There were corresponding accounts payable recorded at December 31, 2013 and 2012 for these liabilities. Both the restricted cash and the accounts payable are classified as current on the accompanying consolidated balance sheets.

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Acquisitions and Dispositions - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]
Purchase of non-controlling interests	$ 48	$ 149

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Earnings per Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings per Share

15. Earnings per Share

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:

	Year Ended December 31,
	2013						2012
	Net Income (In  000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Income (In  000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	12,271		2,436,821	$	5.04	$	15,056		2,624,335	$	5.74
Effect of dilutive securities:
Options		—		746,085				—		735,244
Diluted	$	12,271		3,182,906	$	3.86	$	15,056		3,359,579	$	4.48

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Consolidated Statement of Equity (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock [Member]	Total Stockholders' Equity - PrimeEnergy [Member]	Non-Controlling Interest [Member]
Balance at Dec. 31, 2011	$ 35,753	$ 383	$ 6,446	$ 51,289		$ (31,120)	$ 26,998	$ 8,755
Balance, shares at Dec. 31, 2011		3,836,397
Common stock shares purchase	(4,993)					(4,993)	(4,993)
Net income	14,774			15,056			15,056	(282)
Other comprehensive loss, net of taxes	(35)				(35)		(35)
Purchase of non-controlling interest	(149)		244				244	(393)
Distributions to non-controlling interest	(1,148)							(1,148)
Balance at Dec. 31, 2012	44,202	383	6,690	66,345	(35)	(36,113)	37,270	6,932
Balance, shares at Dec. 31, 2012	3,836,397	3,836,397
Common stock shares purchase	(4,138)					(4,138)	(4,138)
Net income	13,440			12,271			12,271	1,169
Other comprehensive loss, net of taxes	(88)				(88)		(88)
Purchase of non-controlling interest	(48)		113				113	(161)
Distributions to non-controlling interest	(230)							(230)
Balance at Dec. 31, 2013	$ 53,138	$ 383	$ 6,803	$ 78,616	$ (123)	$ (40,251)	$ 45,428	$ 7,710
Balance, shares at Dec. 31, 2013	3,836,397	3,836,397

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Consolidated Balance Sheet (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.10	$ 0.10
Common stock, shares authorized	4,000,000	4,000,000
Common stock, shares issued	3,836,397	3,836,397
Common stock, shares outstanding	2,388,784	2,510,560
Treasury stock, shares	1,447,613	1,325,837

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Stock Options and Other Compensation

12 Months Ended

Dec. 31, 2013

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock Options and Other Compensation

8. Stock Options and Other Compensation

In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At December 31, 2013 and 2012, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Mar. 24, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Trading Symbol	PNRG
Entity Registrant Name	PRIMEENERGY CORPORATION
Entity Central Index Key	0000056868
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		2,369,552
Entity Public Float			$ 52,677,788

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

9. Income Taxes

The components of the provision (benefit) for income taxes for the years ended December 31, 2013 and 2012 are as follows:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Current:
Federal	$	(462	)	$	16
State		266			(130	)
Total current		(196	)		(114	)
Deferred:
Federal		6,549			7,009
State		465			(39	)
Total deferred		7,014			6,970
Total income tax provision	$	6,818		$	6,856

The components of net deferred tax assets and liabilities are as follows:

	At December 31,
(Thousands of dollars)	2013		2012
Current Assets:
Accrued liabilities	$	683	$	613
Allowance for doubtful accounts		118		124
Derivative contracts		677		(83	)
Total current deferred income tax assets	$	1,478	$	654
Non-Current Assets:
Alternative minimum tax credits	$	5,852	$	5,890
Net operating loss carry-forwards		168		114
Percentage depletion carry-forwards		4,543		4,287
Derivative contracts		—		91
Total non-current assets		10,563		10,382
Non-Current Liabilities:
Basis differences relating to managed partnerships		2,462		1,492
Depletion and depreciation		39,694		33,084
Derivative contracts		369		—
Total non-current liabilities		42,525		34,576
Net non-current deferred income tax liabilities	$	31,962	$	24,194

The total provision for income taxes for the years ended December 31, 2013 and 2012 varies from the federal statutory tax rate as a result of the following:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Expected tax expense	$	6,491		$	7,450
State income tax, net of federal benefit		488			(112	)
Percentage depletion		(422	)		(902	)
Other, net		261			420
Total income tax provision	$	6,818		$	6,856

The Company showed a net operating loss on its 2012 federal income tax return, which was carried back to the 2010 and 2011 tax years, resulting in total refunds of $685,000. The net operating loss and related refunds were the result of elections to deduct intangible drilling costs in 2012 which was made upon filing the return in 2013, and the refunds result in the lowering of the current federal income tax expense in 2013.

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Differences relating to oil and gas properties owned through Prime Offshore are reflected under “Depletion and depreciation,” while basis differences relating to the managed partnerships are reflected under “Basis differences relating to managed partnerships.”

The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate.

The Company has $5.9 million in alternative minimum tax (“AMT”) credits which can be used to lower the regular tax liability to the tentative AMT amount in years where the tentative AMT amount is less. These credits do not expire.

The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, and 2009 federal income tax returns have been audited by the Internal Revenue Service, while the 2010, 2011 and 2012 returns remain open for examination. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. State returns for the years 2010, 2011 and 2012 remain open for examination by the relevant taxing authorities.

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Consolidated Statement of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenues
Oil and gas sales	$ 92,785	$ 87,834
Realized gain (loss) on derivative instruments, net	(1,322)	502
Field service income	24,934	20,421
Administrative overhead fees	9,255	8,585
Unrealized gain (loss) on derivative instruments	(649)	3,483
Other income	64	154
Total Revenues	125,067	120,979
Costs and Expenses
Lease operating expense	43,809	39,868
Field service expense	21,027	17,576
Depreciation, depletion, amortization and accretion on discounted liabilities	21,861	23,269
Loss on settlement of asset retirement obligations	40
General and administrative expense	16,659	15,870
Exploration costs	8	10
Total Costs and Expenses	103,404	96,593
Gain on Sale and Exchange of Assets	2,816	730
Income from Operations	24,479	25,116
Other Income and Expenses
Less: Interest expense	4,223	3,577
Add: Interest income	2	91
Income Before Provision for Income Taxes	20,258	21,630
Provision for Income Taxes	6,818	6,856
Net Income	13,440	14,774
Less: Net Income (Loss) Attributable to Non-Controlling Interest	1,169	(282)
Net Income Attributable to PrimeEnergy	$ 12,271	$ 15,056
Basic Income Per Common Share	$ 5.04	$ 5.74
Diluted Income Per Common Share	$ 3.86	$ 4.48

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Additional Balance Sheet Information

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Additional Balance Sheet Information

3. Additional Balance Sheet Information

Accounts receivable at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013			2012
Joint interest billings	$	6,287		$	2,189
Trade receivables		2,014			1,580
Oil and gas sales		9,604			9,362
Other		122			436
		18,027			13,567
Less: Allowance for doubtful accounts		(334	)		(355	)
Total	$	17,693		$	13,212

Accounts payable at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013		2012
Trade	$	1,596	$	3,968
Royalty and other owners		7,391		9,652
Partner advances		3,378		3,589
Prepaid drilling deposits		978		306
Other		2,906		2,053
Total	$	16,249	$	19,568

Accrued liabilities at December 31, 2013 and 2012 consisted of the following:

	December 31,
(Thousands of dollars)	2013		2012
Compensation and related expenses	$	3,062	$	2,517
Property costs		3,119		4,549
Income tax		268		—
Other		383		552
Total	$	6,832	$	7,618

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Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Acquisitions and Dispositions

2. Acquisitions and Dispositions

Historically, the Company has repurchased the noncontrolling interests of the partners and trust unit holders in certain of the Partnerships, which consist primarily of oil and gas interests. The Company purchased such noncontrolling interests in an amount totaling $48,000 in 2013 and $149,000 in 2012.

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Salary Deferral Plan

12 Months Ended

Dec. 31, 2013

Compensation And Retirement Disclosure [Abstract]

Salary Deferral Plan

14. Salary Deferral Plan

The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions of which $525,000 and $463,000 were made in 2013 and 2012, respectively.

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Segment Information and Major Customers

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Information and Major Customers

10. Segment Information and Major Customers

The Company operates in one industry—oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States.

The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company’s total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company’s oil and gas sales in the year 2013.

Oil Purchasers:			Gas Purchasers:
Plains All American Inc.	52	%	Atlas Pipeline Mid-Continent	40	%
Sunoco, Inc.	28	%	Unimark LLC	13	%

Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers.

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Commitments

12 Months Ended

Dec. 31, 2013

Commitments And Contingencies Disclosure [Abstract]

Commitments

6. Commitments

Operating Leases:

The Company has several non-cancelable operating leases, primarily for rental of office space, that have a term of more than one year. The future minimum lease payments for the operating leases at December 31, 2013 are as follows.

(Thousands of dollars)	Operating Leases
2014	$	747
2015		651
2016		545
2017		46
Total minimum payments	$	1,989

Rent expense for office space for the years ended December 31, 2013 and 2012 was $699,000 and $755,000, respectively.

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2013 and 2012 is as follows:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Asset retirement obligation at beginning of period	$	9,012		$	19,013
Liabilities incurred		338			733
Loss on settlement of obligations		40			—
Liabilities settled		(776	)		(15,361	)
Accretion expense		394			1,053
Revisions in estimated liabilities		1,529			3,574
Asset retirement obligation at end of period	$	10,537		$	9,012

The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. During 2013 and 2012 revisions in estimated liabilities for asset retirement obligation resulted primarily from the enactment of new federal regulation requirements for plugging and abandonment.

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Supplementary Information - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Acquisition of Properties, Developed	$ 7	$ 6,482
Acquisition of Properties, Undeveloped		2,030
Exploration Costs	8	10
Development Costs	$ 25,912	$ 66,671

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Property and Equipment

12 Months Ended

Dec. 31, 2013

Property Plant And Equipment [Abstract]

Property and Equipment

4. Property and Equipment

Capitalized interest is included as part of the cost of oil and gas properties. The capitalized rates are based upon the Company’s weighted-average cost of borrowings used to finance the expenditures. There was no interest capitalized during 2013 or 2012.

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Long-Term Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Long-Term Debt

5. Long-Term Debt

Bank Debt:

Effective July 30, 2010, the Company entered into a Second Amended and Restated Credit Agreement between Compass Bank as agent and a syndicated group of lenders (“Credit Agreement”). The Credit Agreement has a revolving line of credit and letter of credit facility of up to $250 million with a final maturity date of July 30, 2017. The credit facility is secured by substantially all of the Company’s oil and gas properties. The credit facility is subject to a borrowing base determined by the lenders taking into consideration the estimated value of PEC’s oil and gas properties in accordance with the lenders’ customary practices for oil and gas loans. This process involves reviewing PEC’s estimated proved reserves and their valuation. The borrowing base is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redetermination. In addition, PEC and the lenders each have at their discretion the right to request the borrowing base be redetermined with a maximum of one such request each year. A revision to PEC’s reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the borrowing base and availability under the credit facility. At any time if the sum of the outstanding borrowings and letter of credit exposures exceed the applicable portion of the borrowing base, PEC would be required to repay the excess amount within a prescribed period.

The Credit Agreement has been amended from time to time to further define the limitations on loans or advances and investments made in the Company’s limited partnerships; modify the Company’s borrowing base and monthly reduction amounts; remove the floor rate component of LIBO rate loans; modify financial reporting requirements to the agent; increase hedging allowances; allow for a one-time advance to be made to the Company’s offshore subsidiary; and amend restrictions on the payments for dividends, distributions or repurchase of PEC’s stock.

The Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio, total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio and interest coverage ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

Under the Credit Agreement, the maximum percentage of production available to enter into commodity hedge agreements is 90% of proved developed producing reserves for each of the next succeeding four calendar years for crude oil and natural gas computed separately. In addition, the Company’s restrictions on the payment of dividends, distributions or purchase of treasury stock is limited to an aggregate of $5.0 million in each calendar year.

At December 31, 2013, the credit facility borrowing base was $140.0 million with no monthly reduction amount. The borrowings made within the credit facility may be placed in a base rate loan or LIBO rate loan. The Company’s borrowing rates in the credit facility provide for base rate loans at the prime rate (3.25% at December 31, 2013) plus applicable margin utilization rates that range from 1.50% to 2.00%, and LIBO rate loans at LIBO published rates plus applicable utilization rates that range from 2.50% to 3.00%. At December 31, 2013, the Company had in place one base rate loan and one LIBO rate loan with effective rates of 5.00% and 2.92%, respectively.

At December 31, 2013, the Company had $112.5 million of borrowings outstanding under its revolving credit facility at a weighted-average interest rate of 3.06%, and $27.5 million available for future borrowings. The combined weighted average interest rate paid on outstanding bank borrowings subject to base rate and LIBO interest was 3.58% for the year ended December 31, 2013, as compared to 3.81% for the year ended December 31, 2012.

The Company has entered into interest rate hedge agreements to help manage interest rate exposure. These contracts include interest rate swaps. Interest rate swap transactions generally involve the exchange of fixed and floating rate interest payment obligations without the exchange of the underlying principal amounts. In July 2012, the Company entered into interest swap agreements for a period of two years, which commence in January 2014, related to $75 million of the Company’s bank debt resulting in a fixed rate of 0.563% plus the Company’s current applicable margin.

Equipment Loan:

On July 31, 2013, the Company entered into a $10.0 million Loan and Security Agreement with JP Morgan Chase Bank (“Equipment Loan”). The Equipment Loan is secured by substantially all of the Company’s field service equipment, carries an interest rate of 3.95% per annum, requires monthly payments (principal and interest) of $184,000, and has a final maturity date of July 31, 2018. As of December 30, 2013, the Company had a total of $9.4 million outstanding on the Equipment Loan.

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Contingent Liabilities

12 Months Ended

Dec. 31, 2013

Commitments And Contingencies Disclosure [Abstract]

Contingent Liabilities

7. Contingent Liabilities

The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. At December 31, 2013, the affiliated Partnerships have established cash reserves in excess of their debts and liabilities, and the Company believes these reserves will be sufficient to satisfy Partnership obligations.

The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

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Supplementary Information - Results of Operations from Oil and Gas Producing Activities (Detail) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Revenue:
Oil and gas sales	$ 92,785	$ 88,336
Costs and Expenses:
Lease operating expenses	43,809	39,868
Exploration costs	8	10
Depreciation, depletion and accretion	19,218	19,883
Income tax expense	10,012	8,941
Total Costs and Expenses	73,047	68,702
Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$ 19,738	$ 19,634

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Supplementary Information - Reserve Quantity Information (Detail)	12 Months Ended
	Dec. 31, 2013 MBbls	Dec. 31, 2012 MBbls
Oil [Member]
Proved Developed Reserves:
Beginning of year	7,178	6,418
Extensions, discoveries and improved recovery	87	224
Revisions of previous estimates	(361)	252
Converted from undeveloped reserves	513	861
Reserves sold
Reserves purchased		168
Production	(730)	(745)
End of year	6,687	7,178
Proved Undeveloped Reserves:
Beginning of year	5,907	2,435
Extensions, discoveries and improved recovery	4,536	3,446
Revisions of previous estimates	864	887
Converted to developed reserves	(513)	(861)
Reserves sold
Reserves purchased
End of year	9,066	5,907
Total Proved Reserves at the End of the Year	15,753	13,085
NGLs [Member]
Proved Developed Reserves:
Beginning of year	2,909
Extensions, discoveries and improved recovery		49
Revisions of previous estimates	(712)	2,860
Converted from undeveloped reserves	199
Reserves sold
Production	(173)
End of year	2,223	2,909
Proved Undeveloped Reserves:
Beginning of year	2,877
Extensions, discoveries and improved recovery	1,541	1,401
Revisions of previous estimates	(512)	1,476
Converted to developed reserves	(199)
Reserves sold
Reserves purchased
End of year	3,707	2,877
Total Proved Reserves at the End of the Year	5,930	5,786
Gas [Member]
Proved Developed Reserves:
Beginning of year	27,833	43,631
Extensions, discoveries and improved recovery	402	1,000
Revisions of previous estimates	6,456	(15,821)
Converted from undeveloped reserves	1,207	3,527
Reserves sold
Reserves purchased		211
Production	(4,270)	(4,715)
End of year	31,628	27,833
Proved Undeveloped Reserves:
Beginning of year	12,613	9,765
Extensions, discoveries and improved recovery	9,538	6,158
Revisions of previous estimates	(1,172)	217
Converted to developed reserves	(1,207)	(3,527)
Reserves sold
Reserves purchased
End of year	19,772	12,613
Total Proved Reserves at the End of the Year	51,400	40,446

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Supplementary Information (Tables)

12 Months Ended

Dec. 31, 2013

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Capitalized Costs Relating to Oil and Gas Producing Activities

CAPITALIZED COSTS RELATING TO

OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
(Thousands of dollars)	2013		2012
Proved Developed oil and gas properties	$	362,186	$	336,135
Proved Undeveloped oil and gas properties		1,937		2,069
Unproved oil and gas properties		—		—
Total Capitalized Costs		364,123		338,204
Accumulated depreciation, depletion and valuation allowance		169,100		150,276
Net Capitalized Costs	$	195,023	$	187,928

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,

EXPLORATION AND DEVELOPMENT ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited)

	Year Ended December 31,
(Thousands of dollars)	2013		2012
Acquisition of Properties, Developed	$	7	$	6,482
Acquisition of Properties, Undeveloped		—		2,030
Exploration Costs		8		10
Development Costs		25,912		66,671

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
(Thousands of dollars)	2013			2012
Future cash inflows	$	1,880,389		$	1,524,137
Future production costs		(769,172	)		(673,629	)
Future development costs		(313,754	)		(179,568	)
Future income tax expenses		(234,191	)		(186,072	)
Future Net Cash Flows		563,272			484,868
10% annual discount for estimated timing of cash flows		(325,044	)		(271,595	)
Standardized Measure of Discounted Future Net Cash Flows	$	238,228		$	213,273

Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2013 and 2012:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Sales of oil and gas produced, net of production costs	$	(48,976	)	$	(48,673	)
Net changes in prices and production costs		(10,149	)		504
Extensions, discoveries and improved recovery		218,648			164,557
Revisions of previous quantity estimates		(733	)		40,964
Net change in development costs		(129,672	)		(145,382	)
Reserves sold		—			—
Reserves purchased		—			6,563
Accretion of discount		21,327			18,451
Net change in income taxes		(23,007	)		(5,952	)
Changes in production rates (timing) and other		(2,483	)		(2,267	)
Net change		24,955			28,765
Standardized measure of discounted future net cash flow:
Beginning of year		213,273			184,508
End of year	$	238,228		$	213,273

Reserve Quantity Information

RESERVE QUANTITY INFORMATION

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
	2013									2012
	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)		Gas (MMcf)
Proved Developed Reserves:
Beginning of year		7,178			2,909			27,833			6,418			—		43,631
Extensions, discoveries and improved recovery		87			—			402			224			49		1,000
Revisions of previous estimates		(361	)		(712	)		6,456			252			2,860		(15,821	)
Converted from undeveloped reserves		513			199			1,207			861			—		3,527
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			168			—		211
Production		(730	)		(173	)		(4,270	)		(745	)		—		(4,715	)
End of year		6,687			2,223			31,628			7,178			2,909		27,833
Proved Undeveloped Reserves:
Beginning of year		5,907			2,877			12,613			2,435			—		9,765
Extensions, discoveries and improved recovery		4,536			1,541			9,538			3,446			1,401		6,158
Revisions of previous estimates		864			(512	)		(1,172	)		887			1,476		217
Converted to developed reserves		(513	)		199			(1,207	)		(861	)		—		(3,527	)
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			—			—		—
End of year		9,066			3,707			19,772			5,907			2,877		12,613
Total Proved Reserves at the End of the Year		15,753			5,930			51,400			13,085			5,786		40,446

Results of Operations from Oil and Gas Producing Activities

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited) 

	Year Ended December 31,
(Thousands of dollars)	2013		2012
Revenue:
Oil and gas sales	$	92,785	$	88,336
Costs and Expenses:
Lease operating expenses		43,809		39,868
Exploration costs		8		10
Depreciation, depletion and accretion		19,218		19,883
Income tax expense		10,012		8,941
Total Costs and Expenses		73,047		68,702
Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	19,738	$	19,634

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Financial Instruments - Schedule of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3 (Detail) (Significant Unobservable Inputs (Level 3) [Member], USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net liabilities at beginning of period	$ (78)	$ (3,507)
Total realized and unrealized (gains) losses:
Included in earnings	(1,971)	3,985
Included in other comprehensive loss	(138)	(54)
Purchases, sales, issuances and settlements	1,322	(502)
Net liabilities at end of period	$ (865)	$ (78)

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

12. Related Party Transactions

The Company, as managing general partner or managing trustee, makes an annual offer to repurchase the interests of the partners and trust unit holders in certain of the Partnerships or Trusts. The Company purchased such interests in an amount totaling $48,000 during 2013 and $149,000 during 2012.

Treasury stock purchases in any reported period may include shares from a related party. In April 2012, the Company purchased 45,179 shares of common stock as treasury shares from a Director for $1.13 million. In December 2013, the Company purchased 4,500 shares of common stock as treasury shares from a Director for $222,750. There were no other related party treasury stock purchases during the years ended December 31, 2013 and 2012.

Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursement for property development and related costs. These receivables are due from joint venture partners, which may include members of the Company’s Board of Directors.

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.

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Supplementary Information

12 Months Ended

Dec. 31, 2013

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Supplementary Information

SUPPLEMENTARY INFORMATION

CAPITALIZED COSTS RELATING TO

OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
(Thousands of dollars)	2013		2012
Proved Developed oil and gas properties	$	362,186	$	336,135
Proved Undeveloped oil and gas properties		1,937		2,069
Unproved oil and gas properties		—		—
Total Capitalized Costs		364,123		338,204
Accumulated depreciation, depletion and valuation allowance		169,100		150,276
Net Capitalized Costs	$	195,023	$	187,928

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,

EXPLORATION AND DEVELOPMENT ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited)

	Year Ended December 31,
(Thousands of dollars)	2013		2012
Acquisition of Properties, Developed	$	7	$	6,482
Acquisition of Properties, Undeveloped		—		2,030
Exploration Costs		8		10
Development Costs		25,912		66,671

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
(Thousands of dollars)	2013			2012
Future cash inflows	$	1,880,389		$	1,524,137
Future production costs		(769,172	)		(673,629	)
Future development costs		(313,754	)		(179,568	)
Future income tax expenses		(234,191	)		(186,072	)
Future Net Cash Flows		563,272			484,868
10% annual discount for estimated timing of cash flows		(325,044	)		(271,595	)
Standardized Measure of Discounted Future Net Cash Flows	$	238,228		$	213,273

See accompanying Notes to Supplementary Information

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS AND CHANGES THEREIN

RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2013 and 2012

(Unaudited)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2013 and 2012:

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Sales of oil and gas produced, net of production costs	$	(48,976	)	$	(48,673	)
Net changes in prices and production costs		(10,149	)		504
Extensions, discoveries and improved recovery		218,648			164,557
Revisions of previous quantity estimates		(733	)		40,964
Net change in development costs		(129,672	)		(145,382	)
Reserves sold		—			—
Reserves purchased		—			6,563
Accretion of discount		21,327			18,451
Net change in income taxes		(23,007	)		(5,952	)
Changes in production rates (timing) and other		(2,483	)		(2,267	)
Net change		24,955			28,765
Standardized measure of discounted future net cash flow:
Beginning of year		213,273			184,508
End of year	$	238,228		$	213,273

See accompanying Notes to Supplementary Information

PRIMEENERGY CORPORATION AND SUBSIDIARIES

SUPPLEMENTARY INFORMATION

RESERVE QUANTITY INFORMATION

Years Ended December 31, 2013 and 2012

(Unaudited)

	As of December 31,
	2013									2012
	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			Oil (MBbls)			NGLs (MBbls)		Gas (MMcf)
Proved Developed Reserves:
Beginning of year		7,178			2,909			27,833			6,418			—		43,631
Extensions, discoveries and improved recovery		87			—			402			224			49		1,000
Revisions of previous estimates		(361	)		(712	)		6,456			252			2,860		(15,821	)
Converted from undeveloped reserves		513			199			1,207			861			—		3,527
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			168			—		211
Production		(730	)		(173	)		(4,270	)		(745	)		—		(4,715	)
End of year		6,687			2,223			31,628			7,178			2,909		27,833
Proved Undeveloped Reserves:
Beginning of year		5,907			2,877			12,613			2,435			—		9,765
Extensions, discoveries and improved recovery		4,536			1,541			9,538			3,446			1,401		6,158
Revisions of previous estimates		864			(512	)		(1,172	)		887			1,476		217
Converted to developed reserves		(513	)		199			(1,207	)		(861	)		—		(3,527	)
Reserves sold		—			—			—			—			—		—
Reserves purchased		—			—			—			—			—		—
End of year		9,066			3,707			19,772			5,907			2,877		12,613
Total Proved Reserves at the End of the Year		15,753			5,930			51,400			13,085			5,786		40,446

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2013 and 2012

(Unaudited) 

	Year Ended December 31,
(Thousands of dollars)	2013		2012
Revenue:
Oil and gas sales	$	92,785	$	88,336
Costs and Expenses:
Lease operating expenses		43,809		39,868
Exploration costs		8		10
Depreciation, depletion and accretion		19,218		19,883
Income tax expense		10,012		8,941
Total Costs and Expenses		73,047		68,702
Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	19,738	$	19,634

See accompanying Notes to Supplementary Information

PRIMEENERGY CORPORATION AND SUBSIDIARIES

NOTES TO SUPPLEMENTARY INFORMATION

(Unaudited)

1. Presentation of Reserve Disclosure Information

Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.

2. Determination of Proved Reserves

The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward of downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

3. Results of Operations from Oil and Gas Producing Activities

The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.

4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.

Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.

Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.

Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.

5. Changes in Reserves

The 2013 and 2012 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

XML

Segment Information and Major Customers - Segment Information by Major Customers (Detail) (Sales [Member])	12 Months Ended
	Dec. 31, 2013
Plains All American Inc., Oil Purchasers [Member]
Revenue, Major Customer [Line Items]
Revenue by major customers	52.00%
Sunoco Inc., Oil Purchasers [Member]
Revenue, Major Customer [Line Items]
Revenue by major customers	28.00%
Atlas Pipeline Mid-Continent, Gas Purchasers [Member]
Revenue, Major Customer [Line Items]
Revenue by major customers	40.00%
Unimark LLC, Gas Purchasers [Member]
Revenue, Major Customer [Line Items]
Revenue by major customers	13.00%

XML

Commitments - Summary of Future Minimum Lease Payments for Non-Cancelable Operating Leases (Detail) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]
2014	$ 747
2015	651
2016	545
2017	46
Total minimum payments	$ 1,989

XML

Consolidated Statement of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Net income	$ 13,440	$ 14,774
Other Comprehensive Loss, net of taxes:
Changes in fair value of hedge positions, net of taxes of $50 and $19, respectively	(88)	(35)
Total other comprehensive loss	(88)	(35)
Comprehensive income	13,352	14,739
Less: Comprehensive income (loss) attributable to non-controlling interest	1,169	(282)
Comprehensive income attributable to PrimeEnergy	$ 12,183	$ 15,021

XML

Description of Operations and Significant Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Description of Operations and Significant Accounting Policies

1. Description of Operations and Significant Accounting Policies

Nature of Operations:

PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico. The Company operates approximately 1,600 wells and owns non-operating interests in over 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PEC owns Eastern Oil Well Service Company (“EOWSC”), EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”). The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.

Consolidation and Presentation:

The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.

Reclassifications:

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.

Subsequent Events:

Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.

Use of Estimates:

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.

Property and Equipment:

The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.

Capitalization of Interest:

Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.

Impairment of Long-Lived Assets:

The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

Fair Value:

The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

Asset Retirement Obligation:

The Company follows the accounting standard for asset retirement obligation. The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.

Income Taxes:

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

General and Administrative Expenses:

General and administrative expenses represent cost and expenses associated with the operation of the Company.

Earnings Per Common Share:

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods.

Statements of Cash Flows:

For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.

Concentration of Credit Risk:

The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.

Hedging:

The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2013 and 2012, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations.

Recently Adopted Accounting Standards:

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities.” This ASU requires enhanced disclosures including both gross and net information about financial and derivative instruments eligible for offset or subject to an enforceable master netting arrangement or similar agreement. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 clarifies the scope of ASU 2011-11 to apply to derivative instruments that are offset or subject to an enforceable master netting arrangement or similar agreement. This clarified guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. The revised requirements of ASU 2011-11 and ASU 2013-01 impacted the disclosures associated with the Company’s derivative instruments (Note 11) and did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“AOCI”). ASU 2013-02 requires a rollforward of changes in AOCI by component and information about significant reclassifications from AOCI to net earnings to be presented in one location, either on the face of the financial statements or in the notes. This new guidance is effective for fiscal years beginning after December 15, 2012 and subsequent interim periods. There was no amounts reclassified out of accumulated other comprehensive income for the year ended December 31, 2013. The requirements of ASU 2013-02 did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.

In July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

XML

Earnings per Share - Computation of Basic and Diluted Earnings (Loss) Per Share (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Net Income, Basic	$ 12,271	$ 15,056
Net Income, Diluted	$ 12,271	$ 15,056
Weighted Average Number of Shares Outstanding, Basic	2,436,821	2,624,335
Effect of dilutive securities, Options	746,085	735,244
Weighted Average Number of Shares Outstanding, Diluted	3,182,906	3,359,579
Net Income Per Share, Basic	$ 5.04	$ 5.74
Net Income Per Share, Diluted	$ 3.86	$ 4.48

XML

Description of Operations and Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Nature of Operations

Nature of Operations:

PrimeEnergy Corporation (“PEC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, West Virginia and Wyoming and the Gulf of Mexico. The Company operates approximately 1,600 wells and owns non-operating interests in over 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PEC owns Eastern Oil Well Service Company (“EOWSC”), EOWS Midland Company (“EMID”) and Southwest Oilfield Construction Company (“SOCC”), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. PEC also owns Prime Offshore L.L.C. (“Prime Offshore”), formerly F-W Oil Exploration LLC, which has owned and operated properties in the Gulf of Mexico. PrimeEnergy Management Corporation (“PEMC”), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 18 limited partnerships and 2 trusts (collectively, the “Partnerships”). The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources.

Consolidation and Presentation

Consolidation and Presentation:

The consolidated financial statements include the accounts of PrimeEnergy Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The proportionate consolidation method is used to account for those undivided interests in oil and gas properties owned by the Company as well as interests held in unincorporated legal entities, such as partnerships, engaged in oil and gas production, which are not controlled by the Company. For those entities which are proportionately consolidated, the proportionate share of each entity’s assets, liabilities, revenue and expenses is included in the appropriate classifications in the consolidated financial statements. Reserve estimates associated with the proportionately consolidated oil and gas interests are calculated for each property at the Partnership level, and depletion, depreciation and amortization (“DD&A”) rates are determined at the Partnership level. The Company’s reserve estimates are based on the ownership percentage of Partnership reserve reports. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements.

Reclassifications

Reclassifications:

Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions.

Subsequent Events

Subsequent Events:

Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure.

Use of Estimates

Use of Estimates:

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset.

Property and Equipment

Property and Equipment:

The Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings.

Capitalization of Interest

Capitalization of Interest:

Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful.

Impairment of Long-Lived Assets:

Impairment of Long-Lived Assets:

The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.

Fair Value

Fair Value:

The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

Asset Retirement Obligation

Asset Retirement Obligation:

The Company follows the accounting standard for asset retirement obligation. The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties (including removal of offshore platforms) at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations.

Income Taxes

Income Taxes:

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

General and Administrative Expenses

General and Administrative Expenses:

General and administrative expenses represent cost and expenses associated with the operation of the Company.

Earnings Per Common Share

Earnings Per Common Share:

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods.

Statements of Cash Flows

Statements of Cash Flows:

For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents.

Concentration of Credit Risk

Concentration of Credit Risk:

The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies.

Hedging

Hedging:

The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company.

The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. At December 31, 2013 and 2012, the entire other comprehensive income amount comprised of the impact of cash flow hedges. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statement of operations.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards:

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, “Disclosures about Offsetting Assets and Liabilities.” This ASU requires enhanced disclosures including both gross and net information about financial and derivative instruments eligible for offset or subject to an enforceable master netting arrangement or similar agreement. This new guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASU 2013-01 clarifies the scope of ASU 2011-11 to apply to derivative instruments that are offset or subject to an enforceable master netting arrangement or similar agreement. This clarified guidance is effective for annual reporting periods beginning on or after January 1, 2013 and subsequent interim periods. The revised requirements of ASU 2011-11 and ASU 2013-01 impacted the disclosures associated with the Company’s derivative instruments (Note 11) and did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income” (“AOCI”). ASU 2013-02 requires a rollforward of changes in AOCI by component and information about significant reclassifications from AOCI to net earnings to be presented in one location, either on the face of the financial statements or in the notes. This new guidance is effective for fiscal years beginning after December 15, 2012 and subsequent interim periods. There was no amounts reclassified out of accumulated other comprehensive income for the year ended December 31, 2013. The requirements of ASU 2013-02 did not have a material impact on the Company’s consolidated financial statements for the year ended December 31, 2013.

In July 2013, the FASB issued ASU 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a similar Tax Loss, or a Tax Credit Carryforward Exists.” ASU 2013-11 provided guidance on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This guidance requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

Presentation of Reserve Disclosure Information

1. Presentation of Reserve Disclosure Information

Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.

Determination of Proved Reserves

2. Determination of Proved Reserves

The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.

Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward of downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

Results of Operations from Oil and Gas Producing Activities

3. Results of Operations from Oil and Gas Producing Activities

The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.

Standardized Measure of Discounted Future Net Cash Flows and Changes therein Relating to Proved Oil and Gas Reserves

4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.

Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.

Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.

Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.

Changes in Reserves

5. Changes in Reserves

The 2013 and 2012 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

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Property and Equipment - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property Plant And Equipment [Abstract]
Interest capitalized	$ 0	$ 0

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Financial Instruments

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Financial Instruments

11. Financial Instruments

Fair Value Measurements:

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2013 and 2012:

December 31, 2013 (Thousands of dollars)	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2013
Assets
Commodity derivative contracts	$	—	$	—	$	1,337		$	1,337
Interest rate derivative contracts		—		—		86			86
Total assets	$	—	$	—	$	1,423		$	1,423
Liabilities
Commodity derivative contracts	$	—	$	—	$	(2,010	)	$	(2,010	)
Interest rate derivative contracts		—		—		(278	)		(278	)
Total liabilities	$	—	$	—	$	(2,288	)	$	(2,288	)

December 31, 2012 (Thousands of dollars)	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2012
Assets
Commodity derivative contracts	$	—	$	—	$	1,347		$	1,347
Total assets	$	—	$	—	$	1,347		$	1,347
Liabilities
Commodity derivative contracts	$	—	$	—	$	(1,371	)	$	(1,371	)
Interest rate derivative contracts		—		—		(54	)		(54	)
Total liabilities	$	—	$	—	$	(1,425	)	$	(1,425	)

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2013 and 2012.

	Year Ended December 31,
(Thousands of dollars)	2013			2012
Net liabilities at beginning of period	$	(78	)	$	(3,507	)
Total realized and unrealized (gains) losses:
Included in earnings(a)		(1,971	)		3,985
Included in other comprehensive loss		(138	)		(54	)
Purchases, sales, issuances and settlements		1,322			(502	)
Net liabilities at end of period	$	(865	)	$	(78	)

^(a)  Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments, and interest rate swap instruments are reported as a reduction to interest expense.

Derivative Instruments:

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.

Interest rate swap derivatives continue to be treated as cash-flow hedges and are used to fix or float interest rates on existing debt. The value of these interest rate swaps at December 31, 2013 is located in accumulated other comprehensive loss, net of tax. Settlement of the swaps, currently scheduled to begin in January 2014, will be recorded within interest expense.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2013 and 2012:

		Fair Value at December 31,
(Thousands of dollars)	Balance Sheet Location	2013			2012
Asset Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Other assets	$	86		$	—
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative contracts		307			189
Natural gas commodity contracts	Derivative contracts		50			1,040
Crude oil commodity contracts	Other assets		980			118
Total		$	1,423		$	1,347
Liability Derivatives:
Derivatives designated as cash-flow hedging instruments:
Interest rate swap contracts	Derivative liability short-term	$	(209	)	$	—
Interest rate swap contracts	Derivative liability long-term		(69	)		(54	)
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term		(1,667	)		(994	)
Natural gas commodity contracts	Derivative liability short-term		(318	)		—
Crude oil commodity contracts	Derivative liability long-term		(25	)		(377	)
Total		$	(2,288	)	$	(1,425	)
Total derivative instruments		$	(865	)	$	(78	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the years ended December 31, 2013 and 2012:

(Thousands of dollars)	Location of gain/loss recognized in income	Amount of gain/loss recognized in income
		2013			2012
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized gain (loss) on derivative instruments, net	$	(1,309	)	$	1,040
Crude oil commodity contracts	Unrealized gain on derivative instruments, net		660			2,443
Natural gas commodity contracts(a)	Realized gain on derivative instruments, net		796			—
Crude oil commodity contracts(a)	Realized gain (loss) on derivative instruments, net		(2,118	)		502
		$	(1,971	)	$	3,985

^(a)  In January 2012, March 2012 and May 2012, the Company unwound and monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for aggregated net proceeds of $1.03 million. The $1.03 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.